TU.S.P4IVC NUREG-1 905

United States Nuclear Regulatory Commission

Protecting People and the Environment

saf(y EwaýUBUa•O Repo•

Related to the License Renewal of

James A. FtzPatrick

Nuclear Power Plant

Docket No. 50-333

Entergy Hud©l•aw Ft Pactkikl LLC

En~te•irgy lHudlar Olpsraf~ons, IMc.-

Office of Nuclear Reactor Regulation
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*U.S.NRC

United States Nuclear Regulatory Commission

Protecting People and the Environment

NUREG-1905

Safety Evaluation Report

Related to the License Renewal of

James A. FitzPatrick

Nuclear Power Plant

Docket No. 50-333

Entergy Nuclear FitzPatrick, LLC

Entergy Nuclear Operations, Inc.

Manuscript Completed: April 2008

Date Published: April 2008

Office of Nuclear Reactor Regulation

Division of License Renewal

ABSTRACT

This safety evaluation report (SER) documents the technical review of the James A. FitzPatrick

Nuclear Power Plant (JAFNPP) license renewal application (LRA) by the United States (US)

Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated July 31, 2006, Entergy Nuclear Operations, Inc. (ENO 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. ENO requests renewal of the JAFNPP operating license (Facility Operating License Number DPR-59) for a period of 20 years beyond the current expiration at

midnight October 17, 2014.

JAFNPP is located approximately 7 miles northeast of Oswego, New York. The NRC issued the

JAFNPP construction permit on May 20, 1970, and operating license on October 17, 1974.

JAFNPP is of a Mark 1, General Electric (GE) 4, boiling water reactor design. GE supplied the

nuclear steam supply system and Stone and Webster originally designed and constructed the

balance of the plant. The JAFNPP licensed power output is 2536 megawatt thermal with a

gross electrical output of approximately 881 megawatt electric.

This SER presents the status of the staff's review of information submitted through

November 05, 2007, the cutoff date for consideration in the SER. On July 31, 2007, the staff

issued a draft SER which identified two open items that had to be resolved before the staff

makes a final determination on the application. The two open items have now been resolved

and SER Section 1.5 summarizes these items and its resolutions. SER Section 6 provides the

staffs final conclusion on the review of the July 31, 2006, JAFNPP LRA, and all its subsequent

amendment letters as listed in SER Appendix B.

iii

TABLE OF CONTENTS

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

T able of C ontents ............................................. .............. v

A bbreviations ............................................................ xiii

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 G uidance ............................................ 1-6

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

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

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

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

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

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

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

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

2.1.3.1 Implementation Procedures and Documentation Sources for

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

2.1.3.2 Quality Controls Applied to LRA Development ............ 2-5

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

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

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

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) .... 2-7

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

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ... 2-14

2.1.4.4 Plant-Level Scoping of Systems and Structures ......... 2-17

2.1.4.5 Mechanical Component Scoping ..................... 2-20

2.1.4.6 Structural Component Scoping ...................... 2-22

2.1.4.7 Electrical Component Scoping....................... 2-23

2.1.4.8 Conclusion for Scoping Methodology .................. 2-24

2.1.5 Screening Methodology ................................. 2-24

2.1.5.1 General Screening Methodology ..................... 2-24

2.1.5.2 Mechanical Component Screening ................... 2-26

2.1.5.3 Structural Component Screening ..................... 2-27

2.1.5.4 Electrical Component Screening ..................... 2-28

2.1.5.5 Conclusion for Screening Methodology ................ 2-30

2.1.6 Summary of Evaluation Findings ............................ 2-30

2.2 Plant-Level Scoping Results ....................................... 2-30

2.2.1 Introduction ............................................ 2-30

v
2.2.2 Summary of Technical Information in the Application

2.3

-. .3 OL.. I Evalu•i orn .........................................

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

Scoping and Screening Results: Mechanical Systems ...................

2.3.1 Reactor Coolant System ...................................

2.3.1.1 Reactor Vessel ...................................

2.3.1.2 Reactor Vessel Internals ...........................

2.3.1.3 Reactor Coolant Pressure Boundary . .................

2.3.2 Engineered Safety Features ...............................

2.3.2.1 Residual Heat Removal System .....................

2.3.2.2 Core Spray System .............................

2.3.2.3 Automatic Depressurization .........................

2.3.2.4 High-Pressure Coolant Injection .....................

2.3.2.5 Reactor Core Isolation Cooling .......................

2.3.2.6 G as Handling ....................................

2.3.2.7 Primary Containment Penetrations ...................

2.3.3 Auxiliary System s ........................................

2.3.3.1 Standby Liquid Control ............................

2.3.3.2 Service W ater ...................................

2.3.3.3 Emergency Diesel Generator .......................

2 .3.3.4 Fuel O il ........................................

2.3.3.5 Fire Protection - W ater ............................

2.3.3.6 Fire Protection - CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..

2.3.3.7 Heating, Ventilation, and Air Conditioning ..............

2.3.3.8 Containment Purge, Containment Atmosphere Dilution, and

Accident Sampling..............................

2.3.3.9 Fuel Pool Cooling and Cleanup ......................

2.3.3.10 Service, Instrument, and Breathing Air ...............

2.3.3.11 Reactor Building Closed Loop Cooling Water ..........

2.3.3.12 Radwaste and Plant Drains ........................

2.3.3.13 Security Generator ..............................

2.3.3.14 Miscellaneous Systems In-Scope for 10 CFR 54.4(a)(2) ..

2.3.3.14A Reactor W ater Cleanup ..........................

2.3.3.14B Extraction Steam ...............................

2.3.3.14C Decay Heat Removal ...........................

2.3.3.14D Feedwater Heater Vents and Drains ................

2.3.3.14E Circulating Water ..............................

2.3.3.14F Turbine Building Closed Loop Cooling ...............

2.3.3.14G Vacuum Priming and Air Removal ................

2.3.3.14H Turbine Lube Oil ...............................

2.3.3.141 Secondary Plant Drains ..........................

2.3.3.14J Raw W ater Treatment .........................

2.3.3.14K Contaminated Equipment Drains ..................

2.3.3.14L Auxiliary Gas Treatment ........................

2.3.3.14M Plumbing, Sanitary, and Lab .....................

2.3.3.14N City Water ......................... ".......

2.3.3.140 Auxiliary Boiler and Accessories ..................

2-30

2-31

2-31

2-31

2-33

.2-36

2-37

2-38

2-40

2-40

2-42

2-44

2-45

2-47

2-49

2-50

2-51

2-52

2-53

2-57

2-59

2-60

2-69

2-74

Post2-76

2-78

2-80

2-82

2-84

2-86

2-88

2-88

2-90

2-91

2-92

2-93

2-95

2-96

2-97

2-99

2-100

2-101

2-102

2-103

2-104

2-105

2.3.3.14P Main Turbine Generator ............. . . . . . . . :

2-107

vi
2.3.3.14Q Sample System .................

2.3.3.14R Steam Seal ....................

2.3.4 Steam and Power Conversion Systems ........

2.3.4.1 Condensate .....................

2.3.4.2 Main Steam ......................

2.3.4.3 Feedwater .......................

2.4 Scopincq and Screening Results: Structures ............

2.4.1 Reactor Building and Primary Containment .....

2.4.1.1 Summary of Technical Information in the

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

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

2.4.2 Water Control Structures.................

2.4.2.1 Summary of Technical Information in the

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

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

2.4.3 Turbine Building Complex and Yard Structures ..

2.4.3.1 Summary of Technical Information in the

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

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

2.4.4 Bulk Commodities ......................

2.4.4.1 Summary of Technical Information in the

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

. . . . . . . . •..

Application

Application

2-108

2-110

2-112

2-112

2-114

2-116

2-118

2-119

2-119

2-120

2-124

2-124

2-124

2-125

2-126

2-127

2-127

2-129

2-131

.............. 2-131

Application .... 2-131

.............. 2-132

2.4.4.3 Conclusion ..................................... 2-134

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control

S ystem s ..................................................

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

2.5.2 Staff Evaluation .................................

2.5.3 Conclusion .....................................

2.6 Conclusion for ScoDina and Screenina .............................

2-134

2-135

2-136

2-136

2-137

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 ls ............................... 3-3

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

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

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

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

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

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

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

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

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or

Enhancem ents ................................... 3-29

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

GALL Report .................................... 3-108

3.0.4 QA Program Attributes Integral to Aging Management Programs .. 3-156

3.0.4.1 Summary of Technical Information in the Application .... 3-156

vii
3.0.4.2 Staff Evaluation ................................. 3-157

3.0.4.3 Conclusion ..................................... 3-158

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

..................... 3-158

3.1.1 Summary of Technical Information in the Application ............ 3-159

3.1.2 Staff Evaluation ........................................ 3-159

3.1.2.1 AMR Results That Are Consistent with the GALL Report . 3-180

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

Which Further Evaluation is Recommended ............ 3-190

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

the GALL Report ................................. 3-201

3.1.3 Conclusion .......................................... 3-206

3.2 Aging Management of Engineered Safety Features Systems ............. 3-206

3.2.1 Summary of Technical Information in the Application ............ 3-206

3.2.2 Staff Evaluation ........................................ 3-207

3.2.2.1 AMR Results That Are Consistent with the GALL Report . 3-218

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

Which Further Evaluation is Recommended ............ 3-225

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

the GALL Report ................................. 3-237

3.2.3 Conclusion .......................................... 3-244

3.3 Aging Management of Auxiliary Systems ........................... 3-244

3.3.1 Summary of Technical Information in the Application ............ 3-245

3.3.2 Staff Evaluation ........................................ 3-245

3.3.2.1 AMR Results That Are Consistent with the GALL Report . 3-264

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

Which Further Evaluation is Recommended ............ 3-286

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

the GALL Report ................................. 3-309

3.3.3 Conclusion ............................................ 3-333

3.4 Aging Management of Steam and Power Conversion Systems ........... 3-333

3.4.1 Summary of Technical Information in the Application............ 3-334

3.4.2 Staff Evaluation ........................................ 3-334

3.4.2.1 AMR Results That Are Consistent with the GALL Report . 3-342

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

Which Further Evaluation is Recommended ............ 3-344

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

the GALL Report ................................. 3-358

3.4.3 Conclusion ................................... ....... 3-362

3.5 Aging Management of Structures and Component Supports ............. 3-363

3.5.1 Summary of Technical Information in the Application ............ 3-363

3.5.2 Staff Evaluation ...................................... 3-363

3.5.2.1 AMR Results That Are Consistent with the GALL Report . 3-376

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

Which Further Evaluation is Recommended ............ 3-386

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

the GALL Report................................. 3-413

3.5.3 Conclusion ............................................ 3-419

viii
3.6 Agingi Management of Electrical and Instrumentation and Controls ........ 3-419

3.6.1 Summary of Technical Information in the Application ............ 3-419

3.6.2 Staff Evaluation ....................................... 3-419

3.6.2.1 AMR Results That Are Consistent with the GALL Report . 3-423

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

Which Further Evaluation is Recommended ............ 3-425

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

the GALL Report ................................ 3-432

3.6.3 Conclusion ........................................... 3-442

3.7 Conclusion for Aging Management Review Results .................... 3-442

Time-limited Aging Analyses.....................................4-1

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

4. 1.1 Summary of Technical Information in the Application .............. 4-1

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

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

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

4.2.1 Reactor Vessel Fluence ................................... 4-3

4.2.1 .1 Summary of Technical Information in the Application....... 4-3

4.2.1.2 Staff Evaluation .................................. 4-3

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

4.2.1.4 Conclusion................................... I.... 4-4

4.2.2 Pressure-Temperature Limits ............... ................ 4-5

-4.2.2.1 Summary of Technical Information in the Application....... 4-5

4.2.2.2 Staff Evaluation .................................. 4-5

4.2.2.3 UFSAR Supplement............................... 4-6

4.2.2.4 Conclusion ...................................... 4-7

4.2.3 Charpy Upper-Shelf Energy ................................ 4-7

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

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

4.2.3.3 UFSAR Supplement.............................. 4-12

4.2.3.4 Conclusion ..................................... 4-12

4.2.4 Adjusted Reference Temperature........................... 4-13

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

4.2.4.2 Staff Evaluation .................................. 4-13

4.2.4.3 UFSAR Supplement.............................. 4-14

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

4.2.5 Reactor Vessel Circumferential Weld Inspection Relief ........... 4-15

4.2.5.1 Summary of Technical Information in the Application...... 4-15

4.2.5.2 Staff Evaluation .................................. 4-16

4.2.5.3 UFSAR Supplement.............................. 4-22

4.2.5.4 Conclusion ..................................... 4-23

4.2.6 Reactor Vessel Axial Weld Failure Probability .................. 4-24

4.2.6.1 Summary of Technical Information in the Application...... 4-24

4.2.6.2 Staff Evaluation .................................. 4-24

4.2.6.3 UFSAR Supplement.............................. 4-29

4.2.6.4 Conclusion. ....................... 7.............4-30

4.3 Metal Fatigue................................................. 4-30

ix
4.3.1 C lass 1 Fatigue ......................................... 4-31

4.3.1.1 Reactor Vessel .................................. 4-31

4.3.1.2 Reactor Vessel Internals .......................... 4-35

4.3.1.3 Class 1 Piping and Components ..................... 4-37

4.3.2 Non-Class 1 Fatigue ..................................... 4-38

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

4.3.2.2 Staff Evaluation .................................. 4-38

4.3.2.3 UFSAR Supplement .............................. 4-38

4.3.2.4 Conclusion .................................... 4-38

4.3.3 Effects of Reactor Water Environment on Fatigue Life ........... 4-39

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

4.3.3.2 Staff Evaluation .................................. 4-40

4.3.3.3 UFSAR Supplement .............................. 4-44

4.3.3.4 Conclusion ...................................... 4-44

4.4 Environmental Qualification of Electric Equipment ...................... 4-44

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

4.4.2 Staff Evaluation ......................................... 4-45

4.4.3 UFSAR Supplement ...................................... 4-46

4.4.4 Conclusion .............................................. 4-46

4.5 Concrete Containment Tendon Prestress ............................. 4-46

4.5.1 Summary of Technical Information in the Application ............. 4-46

4.5.2 Staff Evaluation ......................................... 4-46

4.5.3 UFSAR Supplement ...................................... 4-46

4.5.4 Conclusion ............... . .......... ............... 4-46

4.6 Containment Liner Plate, Metal Containment, and Penetrations Fatigque Analysis

............................................... 4-46

4.6.1 Fatigue of Primary Containment ............................. 4-47

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

4.6.1.2 Staff Evaluation .................................. 4-47

4.6.1.3 UFSAR Supplement .............................. 4-48

4.6.1.4 Conclusion ...................................... 4-48

4.7 Other Plant-Specific TLAAs ....................................... 4-49

4.7.1 Recirculation Isolation Valves .............................. 4-49

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

4.7.1.2 Staff Evaluation .................................. 4-49

4.7.1.3 UFSAR Supplement .............................. 4-51

4.7.1.4 Conclusion ...................................... 4-51

4.7.2 Fatigue Crack Growth Analysis for UFSAR Section 16.3.2.2 ........ 4-51

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

4.7.2.2 Staff Evaluation ................................ 4-51

4.7.2.3 Conclusion ....................................... 4-52

4.7.3 TLAA in BWRVIP Documents ............................. 4-52

4.7.3.1 BWRVIP-05, RPV Circumferential Welds .............. 4-52

4.7.3.2 BW RVIP-25, Core Plate ........................... 4-53

4.7.3.3 BWRVIP-38, Shroud Support....................... 4-56

4.7.3.4 BWRVIP-47-A, Lower Plenum ....................... 4-57

4.7.3.5 BWRVIP-74, Reactor Pressure Vessel ................ 4-58

4.7.3.6 BW RVIP-76, Core Shroud .......................... 4-59

x
4.7.4 Assessment of Plant-Specific Fatigue Flaw Growth and Fracture

Mechanics Evaluations ................................ 4-61

4.7.4.1 Summary of Technical Information in the Application ..... 4-61

4.7.4.2 Staff Evaluation .................................. 4-61

4.7.4.3 UFSAR Supplement ............................... 4-66

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

4.8 Conclusion for Time-Limited Aging Analyses .......................... 4-66

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

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

APPENDIX A, JAFNPP License Renewal Commitments ........................... A-1

APPENDIX B, Chronology .................................................. B-1

APPENDIX C, Principal Contributors .......................................... C-1

APPENDIX D, References .................................................. D-1

Tables

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

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

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

Components in the GALL Report ........................................... 3-160

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

G A LL Report ............................................................ 3-208

Table 3.3-1 Staff Evaluation for Auxiliary Systems in the GALL Report .............. 3-247

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

G A LL Report ........................................................... 3-335

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

G A LL Report ........................................................... 3-364

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

G A LL Report ........................................................... 3-420

Table 4.2.3.2-1 Results of Applicant's and the Staffs Independent Upper-Shelf

Energy/Equivalent Margin Analysis Calculations for the Limiting Plate and Weld Materials for

Upper-Shelf Energy ...................................................... 4-11

Table 4.2.5-1 Comparison of NRC and JAFNPP 54 EFPY Mean RTNDT Calculations to the

xi
64 EFPY Mean RTNDT Calculations for the Limiting Combustion Engineering Owners Group

Case Study on BW RVIP-05 ................................................ 4-21

Table 4.2.6-1 Comparison of NRC and the Applicant's 54 EFPY Mean RTNDT Calculations for

JAFNPP Reactor Vessel Beltline Axial Weld Probability of Failure Analyses ........... 4-27

xii
ABBREVIATIONS

AC alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ACSR aluminum conductor steel reinforced

ADAMS Agencywide Document Access and Management System

ADS automatic depressurization system

AEM aging effect/mechanism

AERM aging effect requiring management

AFW auxiliary feedwater

AHU air handling unit

AMC aging management structural

AME aging management electrical

AMM aging management mechanical

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

AOV air operated valve

APCSB Auxiliary and Power Conversion Systems Branch

ARI alternate rod insertion

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

BIP Bolting Integrity Program

BOP balance-of-plant

BTP Branch Technical Position

BWR boiling water reactor

BWROG Boiling Water Reactor Owners Group

BWRVIP Boiling Water Reactor Vessel and Internals Program

CAD containment air dilution

CASS cast austenitic stainless steel

CB&I Chicago Bridge and Iron

CDF core damage frequency

CEOG Combustion Engineering Owners Group

CF chemistry factor

CFR Code of Federal Regulations

CHUG CHECKWORKS Users Group

Cl confirmatory item

CIl containment inservice inspection

CLB current licensing basis

CO 2 carbon dioxide

CP containment purge

xiii
CR condition report

CRD control rod drive

CRDRL control rod drive return line

CWS circulating water system

CS core spray

CST condensate storage tank

Cu copper

CUF cumulative usage factor

CRUSE Charpy upper-shelf energy

DBA design basis accident

DBD design basis document

DBE design basis event

DC direct current

DHR decay heat removal

ECCS emergency core cooling system

EDG emergency diesel generator

EFPY effective full power years

EMA equivalent margin analysis

ENN Entergy Nuclear North

ENO Entergy Nuclear Operations

EPIC Emergency Plant Information Computer

EOL end of life

EPRI Electric Power Research Institute

EQ environmental qualification

ESF engineered safety features

ESW emergency service water

FAC flow-accelerated corrosion

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FF fluence factor

FMP Fatigue Monitoring Program

FP fire protection

FPC fuel pool cooling

FPCC fuel pool cooling and cleanup

FR Federal Register

FSAR final safety analysis report

FSER final safety evaluation report

ft-lb foot-pound

FW feedwater

GALL Generic Aging Lessons Learned Report

GDC general design criteria or general design criterion

GE General Electric

GElS Generic Environmental Impact Statement

xiv
GL generic letter

GSI generic safety issue

HELB high-energy line break

HPCI high pressure coolant injection

HPSI high pressure safety injection

HT heat transfer

HVAC heating, ventilation, and air conditioning

HWC hydrogen water chemistry

I&C instrumentation and controls

IASCC irradiation-assisted stress corrosion cracking

ID inside diameter

IEEE Institute of Electrical and Electronics Engineers

IGSCC inter-granular stress corrosion cracking

IN Information Notice, insulation (electrical)

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

IPE Individual Plant Examination

IR insulation resistance

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

JAFNPP James A. FitzPatrick Nuclear Power Plant

KV or kV kilo-volt

LCO limiting condition for operation

LMS leakage monitoring system

LOCA loss of coolant accident

LR license renewal

LRA license renewal application

LRBD license renewal boundary drawings

LRD license renewal document

LRIS license renewal information system

LRPD license renewal project document/report

LRPG license renewal project guidelines

MEB metal-enclosed bus

MIC microbiologically influenced corrosion

MS main steam

MSIV main steam isolation valve

MSLCS main steam leak collection system

N2 nitrogen

N/A not applicable

n/cm 2 neutrons per square centimeter

xv
NBVI nuclear boiling vessel instrumentation

NDE nondestructive examination

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

Ni nickel

NMCA noble metal chemical addition

NPS nominal pipe size

NRC US Nuclear Regulatory Commission

NSW normal service water

NWC normal water chemistry

NYPA New York Power Authority

OD outside diameter

OGH off-gas holdup

01 open item

PASNY Power Authority of the State of New York

PASS post-accident sampling system

PDI performance demonstration initiative

PFM probabilistic fracture mechanics

pH potential of hydrogen

P&ID piping and instrumentation diagram/drawing

ppb parts per billion

ppm parts per million -

PSPM periodic surveillance and preventive maintenance

P-T pressure-temperature

PT penetrant testing

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized water reactor

QA quality assurance

RAI request for additional information

RBCLC reactor building closed loop cooling

RBCLCW reactor building closed loop cooling water

RCIC reactor core isolation cooling

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG regulatory guide

RHR residual heat removal

RHRSW residual heat removal service water

RO refueling outage

RPV reactor pressure vessel

RR reactor recirculation

RTNDT reference temperature. (nil ductility transition)

RV reactor vessel

RVID Reactor Vessel Integrity Database

xvi
RWCU reactor water cleanup

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SE Safety Evaluation

SER Safety Evaluation Report

SGT standby gas treatment system

SIF stress intensification factor

SIV safety injection valve

SO2 sulfur dioxide

SOV solenoid valve

SRP Standard Review Plan

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

Power Plants

SRV safety/relief valve

SS sample system, stainless steel

SSC system, structure, and component

sol sub-open item

SW service water

TAP torus attached piping

TB turbine building

TBCLC turbine building closed loop cooling

TES Teledyne Engineering Services

TIP traversing incore probe

TLAA time-limited aging analysis

TS technical specification

US United States

UFSAR Updated Final Safety Analysis Report

USE upper-shelf energy

UT ultrasonic testing

yr year

Zn zinc

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

of the vessel

xvii

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

James A. FitzPatrick Nuclear Power Plant (JAFNPP) as filed by the Entergy Nuclear

Operations, Inc. (ENO or the applicant). By letter dated July 31, 2006, ENO submitted its

application to the United States (US) Nuclear Regulatory Commission (NRC) for renewal of the

JAFNPP 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 Ngoc B. (Tommy) Le. Mr. Le may be contacted by telephone at 301-415-1458

or by electronic mail at NBL@nrc.gov. Alternatively, written correspondence may be sent to the

following address:

License Renewal and Environmental Impacts Program

US Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: Ngoc B. (Tommy) Le, Mail Stop 011-F1

In its July 31, 2006, submission letter, the applicant requested renewal of the operating license

issued under Section 104b (Operating License No. DPR-59) of the Atomic Energy Act of 1954,

as amended, for JAFNPP for a period of 20 years beyond the current expiration at midnight

October 17, 2014. JAFNPP is located approximately seven miles northeast of Oswego, New

York. The NRC issued the JAFNPP construction permit on May 20, 1970, and the operating

license on October 17, 1974. JAFNPP is of a Mark 1, GE 4, boiling water reactor design. GE

supplied the nuclear steam supply system and Stone and Webster originally designed and

constructed the balance of the plant. The JAFNPP licensed power output is 2536 megawatt

thermal with a gross electrical output of approximately 881 megawatt electric. 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 technical review of safety

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

For Renewal Of Operating Licenses For Nuclear Power Plant" 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

JAFNPP license renewal is based on (1) the applicant's LRA and its responses to the staff's

requests for additional information (RAIs) and (2) the staff's onsite audits of the applicant's

aging management programs and reviews. The applicant supplemented the LRA and provided

clarifications through its responses to staff's RAls in audits, meetings, and docketed

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

submitted through November 5, 2007. The staff reviewed information received after that date

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

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The public may view the LRA and all pertinent information and materials, including the UFSAR,

at the NRC Public Document Room, 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 following public

libraries: State University of New York Penfield Library, 7060 State Route 104, Oswego, New

York 13126; and Oswego Public Library, 140-142 East Second Street, Oswego, New York

13126. In addition, the public may find the LRA, as well as materials related to the license

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

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

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

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

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

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

(SRP-LR), dated September 2005.

SER Sections 2 through 4 address the staffs evaluation of license renewal issues considered

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

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

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

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

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

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

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

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

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

renewal for JAFNPP. The staff issued draft plant-specific GElS Supplement 31, "Generic

Environment Impact Statement for License Renewal of Nuclear Plants regarding James A.

FitzPatrick Nuclear Power Plant," on June 8, 2007 (ADAMS Accession No. ML071420019). The

final plant-specific GElS Supplement 31, was issued on January 18, 2008.

1.2 License Renewal Background

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

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

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

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

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

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

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

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

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

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

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

license renewal for nuclear power plants.

1-2
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 certain 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 existing plant 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 simpler, more stable, and more predictable than the previous 10 CFR Part 54 process.

In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging

effects rather than on the identification of age-related degradation unique to license renewal.

The staff made these rule changes to ensure that important systems, structures, and

components (SSCs) will continue to perform their intended functions during periods of extended

operation. In addition, the amended 10 CFR Part 54 process clarifies and simplifies the

integrated plant assessment for consistency with the revised focus on passive, long-lived

structures and components (SCs).

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

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

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

Environmental Policy Act of 1969.

1.2.1 Safety Review

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

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

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

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

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

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

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

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

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

safety-related functions, and (3) are relied on for compliance with the NRC fire protection,

environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without

scram (ATWS), and station blackout (SBO) regulations.

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. As required by 10 CFR 54.21(a), license renewal applicants must

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

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

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

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

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

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

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

required throughout the period of extended operation.

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

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

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

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

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

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

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

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

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

In 2005, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format and

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

Nuclear Energy Institute (NEI) 95-10, Revision 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

in reviewing the LRA.

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

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

summarizes staff-approved aging management programs (AMPs) for many SCs subject to an

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

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

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

evaluations, programs, and activities credited for managing aging for most SCs 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 GElS to document its evaluation of possible

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

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

plants and are codified in 10 CFR Part 51 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)." Pursuant to 10 CFR 51.53(c)(3)(1), license

renewal applicants may incorporate these generic findings in their environmental reports. In

1-4
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 GELS. As part of its scoping process,

the staff held a public meeting on October 12, 2006, in Oswego, New York, to identify

plant-specific environmental issues. Draft plant-specific GElS Supplement 31 documents the

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

renewal action. The staff held two other public meetings on August 1, 2007, in Oswego, New

York, to discuss draft, plant-specific GElS Supplement 31. After considering comments on the

draft, the staff published the final plant-specific GElS Supplement 31 separately from this

report.

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)-, theNRC requires license renewal applicants 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 LRAs 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:

... 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. 10, lists JAFNPP operating license number DPR-59. The applicants request

that conforming changes be made to Article VII of the indemnity agreement, and

Item 3 of the Attachment to that agreement, specifying the extension of

agreement until the expiration date of the renewed JAFNPP facility operating

license sought in this application. In addition, should the license number be

changed upon issuance of the renewal license, the applicants request 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 number upon issuance of the renewed license,

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

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

1-5
Pursuant to 10 CFR 54.21, "Contents of Application - Technical Information," the NRC requires

that LRAs 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) an 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 three months before the scheduled completion of the staffs 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. The applicant has submitted such LRA

amendments as listed in Appendix B of the SER and thus satisfies the license renewal

requirements of 10 CFR 54.21(b).

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 necessary to

manage aging effects during the period of extended operation. In LRA Appendix D, the

applicant stated that it had not identified any technical specification changes necessary for

issuance of the renewed JAFNPP 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 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 theSER sections in which the staff

addresses them.

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Table 1.4-1 Current Interim Staff Guidance

ISG Issue Purpose SER Section

(Approved ISG Number)

Nickel-alloy components in the Cracking of nickel-alloy Not applicable (Pressurized Water

reactor coolant pressure boundary components in the reactor pressure Reactors only)

(LR-ISG-19B) boundary.

ISG under development. NEI and

EPRI-MRP will develop an

augmented inspection program for

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

not be completed until the NRC

approves an augmented inspection

program for nickel-alloy base metal

components and welds as

proposed by EPRI-MRP.

Corrosion of drywell shell in Mark I To address concerns related to SER 3.5.2.2.1

containments corrosion of drywell shell in Mark I

(LR-ISG-2006-01) containments.

1.5 Summary of Open Items and Resolutions

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

June 20, 2007, the staff identified the following open items (Ols). An item is considered open if,

in the staff's judgement, it does not meet all applicable regulatory requirements at the time of

the issuance of this SER. The staff has assigned a unique identifying number to each 01.

01 4.2.1-1: (SER Section 4.2.1 - Reactor Vessel Neutron Fluence)

The staff reviewed GE-NE-B1 100732-01 report on analysis of the 120 °capsule removed at

13.4 effective full power years (EFPYs) of operation submitted by the applicant to determine if

calculation of fluence values were in accordance with the guidance of RG 1.190, "Calculational

and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence." The staff

determined that the GE-NE-B1 100732-01 report did not conform to the RG 1.190. The

applicant had stated at the time that it would submit a new fluence calculation to the staff for

review when complete. This item was identified as 01 4.2.1-1 in the staff SER With Open Items

issued on July 31, 2007.

The applicant, in its November 5, 2007, response to 01 4.2.1-1, submitted a summary of a new

analysis for its determination of maximum pressure vessel neutron fluence.

The staff reviewed the applicant's new calculated values and found the new calculation

acceptable as it is adhered with the guidance of RG 1.190. The staff had determined that the

original values that were submitted in LRA remain bounded by the new calculated values;

therefore, 014.2.1-1 is closed. The staff's evaluation of this item is detailed in SER Section 4.0.

1-7
As noted in the staffs SER with Open Items issued July 31, 2007, for 01 4.2.1-1, the applicant's

reactor pressure vessel neutron fluence evaluation for the period of extended operation

impacted the staff's review of other items in LRA Section 4.2.2.

As stated in the staffs SER with Open Items issued July 31, 2007, the staff had found

information submitted for the following TLAA sections of the LRA acceptable pending resolution

of 01 4.2.1-1. Now that 01 4.2.1-1 is resolved and closed, the staff finds the following sub-Ols

(sOls) closed:

sOl 4.2.2-1: (SER Section 4.2.2 - Pressure-Temperature Limits)

The staff's review of P-T limits was based on the applicant's original fluence values in LRA

Section 4.2.1. These original values had been previously found acceptable as documented in

the previously issued SER with Open Items dated July 31, 2007. The staff finds that these

original values remain bounded by the new calculated values submitted by the applicant in a

letter dated November 5, 2007. Therefore, sOl 4.2.2-1 is now closed.

The staff determined that the TLAA for P-T limits is acceptable because (1) the projected 54

EFPY fluence and ART values are in fact less than the 200 OF suggested in RG 1.99, Section 3,

and (2) changes to the P-T limit curves will be implemented by the license amendment process

(i.e., through revisions of the plant TS) in accordance with 10 CFR 50.60 and 10 CFR Part 50,

Appendix G.

s0l 4.2.3-1: (SER Section 4.2.3 - Charpy Upper-Shelf-Energy)

The staff determined that the applicant correctly used RG 1.99, Revision 2, Position 1 to

calculate the predicted percentage decrease in upper-shelf energy (USE) conservatively for the

period of extended operation. The staff also independently calculated (1) the end of life (EOL)

USE values for the beltline plate materials at 54 EFPY and (2) the equivalent margin analysis

(EMA) of the percent drop in USE for the beltline weld materials through 54 EFPY. Verifying the

drop in USE values from neutron irradiation using the RG 1.99, Revision 2 methodology, the

staff finds that all the beltline materials meet 10 CFR Part 50, Appendix G, EOL USE or EMA

requirements and SRP-LR Section 4.2.3.1.1.2 criteria for USE/EMA TLAAs in accordance with

10 CFR 54.21(c)(1)(ii). SER Table 4.2.3-1 summarizes the results of both the applicant's and

the staff's independent USE/EMA calculations for the limiting plate and weld materials.

The staff's review was based on the fluence values provided by the applicant in LRA

Section 4.2.1. The staff finds that the values that were submitted by the applicant's LRA

submitted on August 1, 2006, remains bounded by the new calculated values submitted by the

applicant in a letter dated November 5, 2007. Therefore, sOl 4.2.3-1 is now closed.

sOl 4.2.4-1: (SER Section 4.2.4 - Adjusted Reference Temperature)

The staff confirmed that lower shell axial welds 2-233 A, B, and C fabricated from Heat

No. 27204/12008 were the limiting 1/4T reference temperature (nil-ductility transition) (RTNDT)

reactor vessel components. The staff calculated a limiting 1/4T RTNDT value of 132.1 OF for this

plate material based on the chemistry factor (CF) table for plate/forging materials in RG 1.99,

Revision 2 and a 1/4T fluence of 0.174 x 10"s n/cm 2 (E > 1.0 MeV) at 54 EFPY. The 1/4T RTNDT

1-8
value calculated by the staff at 54 EFPY is within 3.2 OF of that calculated (i.e., 135.3 OF) by the

applicant for this material. As the staff's independent 1/4T RTNOT value agreed with that

calculated by the applicant, the staff found the applicant's calculated and projected limiting 1/4T

RTNOT value for the reactor vessel at 54 EFPY valid and found the TLAA on 1/4T RTNDT values

for the reactor vessel through 54 EFPY acceptable in accordance with 10 CFR 54.21(c)(1)(ii).

The staffs review was based on the applicant's fluence values in LRA Section 4.2.1. The staff

finds that the values that were submitted by the applicant's LRA on August 1, 2006, remains

bounded by the new calculated values submitted by the applicant in a letter dated

November 5, 2007. Therefore, sOl 4.2.4-1 is now closed.

s0l 4.2.5-1: (SER Section 4.2.5 - Reactor Vessel Circumferential Weld Inspection Relief)

The staff finds the applicant's evaluation for this TLAA acceptable because the 54 EFPY

conditional failure probability for the reactor vessel circumferential welds is bounded by the

analysis in the staff SER dated July 28, 1998, and the applicant will use procedures and training

to limit cold over-pressure events during the period of extended operation. This analysis

satisfies the evaluation requirements of the staff SER dated July 28, 1998; however, the

applicant still must request relief from the circumferential weld examination for the period of

extended operation in accordance with 10 CFR 50.55a.

The staff's review was based on the applicant's fluence values in LRA Section 4.2.1. The staff

finds that the values that were submitted by the applicant's LRA submitted on August 1, 2006,

remains bounded by the new calculated values submitted by the applicant in a letter dated

November 5i 2007. Therefore, sOl 4.2.5-1 is now closed.

s0l 4.2.6-1: (See SER Section 4.2.6 - Reactor Vessel Axial Weld Failure Probability)

The staff reviewed LRA Section 4.2.6, to verify pursuant to 10 CFR 54.21(c)(1)(ii) that the

analyses have been projected to the end of the period of extended operation. The staff

reviewed the applicant's TLAA of the reactor vessel axial weld failure probability, as

summarized in LRA Section 4.2.6, and its response to RAI 4.2.6.1 dated February 12, 2007,

supplemented by letter dated June 20, 2007, and determines that the applicant appropriately

described how the conditional failure probability for the reactor vessel axial welds is bounded by

the analysis in the staff supplemental SER dated March 7, 2000, on the BWRVIP-05 Report for

the period of extended operation. The staff therefore finds the applicant's TLAA Section 4.2.6

and UFSAR supplement summary description A.2.2.1.6 acceptable. The staff concludes that

the applicant's TLAA for the reactor vessel axial weld failure probability comply with the

10 CFR 54.21 (c)(1)(ii) TLAA acceptance criterion.

The staff's review was based on the applicant's fluence values in LRA Section 4.2.1. The staff

finds that the new calculated value submitted by the applicant in a letter dated

November 5, 2007 remains bounded by the value that Was submitted by the applicant's LRA

submitted on August 1, 2006. Therefore, sOl 4.2.6-1 is now closed.

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s0l B.1.24-3: (See SER Section 3.0.3.2.16 - Reactor Vessel Surveillance Program)

On the basis of the staff's review for LRA item B.1.24 discussed in SER Section 3.0 and the

new calculated fluence value submitted by the applicant in a letter dated November 5, 2007, the

staff finds that the values that were submitted by the applicant's LRA submitted on

August 1, 2006, remains bounded by the new calculated values submitted by the applicant in a

letter dated November 5, 2007. Therefore, the applicant's implementation of the Integrated

Surveillance Program (ISP), as specified in the BWRVIP-1 16 Report, remains valid and as

such, the various attributes in the ISP are not affected by the new methodology of calculating

the neutron fluence values. The staff finds that the applicant has demonstrated that the effects

of aging due to loss of fracture toughness of the reactor pressure vessel beltline region 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). Therefore,

sOl B.1.24-3 is now closed.

01 4.3.3-1: (SER Section 4.3.3 - Effects of Reactor Water Environment on Fatigue Life)

By letter dated August 14, 2007, as supplemented by letter dated November 5, 2007, the

applicant responded to RAI 4.3.3-1 and resolved the staffs issue identified in 01 4.3.3-1.

In these letters, the applicant amended the LRA and supplemented Commitment No. 20 to

justify its environmentally-assisted fatigue analysis. The November 5, 2007, letter clarified that

Option 1 of Commitment No. 20 for refined CUF calculations is consistent with NRC

recommendations for periodic CUF updates in "monitoring and trending" (i.e., program

element 4) of GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure Boundary,"

and for "corrective actions" in GALL AMP X.M1. The applicant also clarified that Options 2

and 3 of Commitment No. 20 are corrective actions consistentwith those recommended in

"corrective action" (i.e., program element 7) of the same GALL AMP. With these clarifications,

the applicant amended the LRA to bring Commitment No. 20 within the scope of the Fatigue

Monitoring Program and to credit this AMP as the basis for acceptance of this TLAA as in

accordance with 10 CFR 54.21(c)(1)(iii).

After reviewing the letter dated August 14, 2007, as supplemented by the letter dated

November 5, 2007, the staff finds the applicant's clarification of these changes consistent with

NRC recommendations in GALL AMP X.M1 and therefore are acceptable. The staff concludes

that the applicant's response is acceptable and, therefore, 01 4.3.3.1 is closed. The staff's

evaluation of the applicant's response is detailed in SER Section 4.3.3.

1.6 Summary of Confirmatory Items

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

November 5, 2007, the staff identified no confirmatory items. An item is considered

confirmatory if the staff and the applicant have reached a satisfactory resolution but the

applicant has not yet formally submitted the resolution. The staff has assigned a unique

identifying number to each confirmatory item, if any.

There are no confirmatory items in this SER

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1.7 Summary of Proposed License Conditions

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

the applicant, the staff identified three proposed license conditions.

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

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

of the renewed license.

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

be completed prior to the period of extended operation.

The third license condition requires the implementation of the most recent staff-approved

version of the Boiling Water Reactor Vessels and Internals Project (BWRVIP) Integrated

Surveillance Program (ISP) as the method to demonstrate compliance with the requirements of

10 CFR Part 50, Appendix H. Any changes to the BWRVIP ISP capsule withdrawal schedule

must be submitted for NRC staff review and approval. Any changes to the BWRVIP ISP

capsule withdrawal schedule which affects the time of withdrawal of any surveillance capsules

must be incorporated into the licensing basis. If any surveillance capsules are removed without

the intent to test them, these capsules must be stored in a manner which maintains them in a

condition which would support re-insertion into the reactor pressure vessel, if necessary.

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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodologv

2.1.1 Introduction

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

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

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

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

the scope of license renewal.

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

identifying SSCs at the James A. FitzPatrick Nuclear Power Plant (JAFNPP), within the scope

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

Regulatory Commission (NRC) (the staff) reviewed the Entergy Nuclear Operations, Inc. (ENO

or the applicant) scoping and screening methodology to determine whether it meets the scoping

requirements of 10 CFR 54.4(a) and the screening requirements of 10 CFR 54.21.

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

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

Power Plants" (the Rule), statements of consideration on the Rule, and Regulatory Guide

(RG) 1.188, which endorses the guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6,

"Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License

Renewal Rule," dated June 2005. The applicant also considered the correspondence between

the staff, other applicants, and the NEI.

2.1.2 Summary of Technical Information in the Application

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

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

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

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

such SCs in the following LRA sections:

° Section 2.2, "Plant Level Scoping Results"

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

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

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

Systems"

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

results in the following LRA sections:

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

* Section 3.2, "Engineered Safety Features Systems"

* Section 3.3, "Auxiliary Systems"

* Section 3.4, "Steam and Power Conversion Systems"

* Section 3.5, "Structures and Component Supports"

* Section 3.6, "Electrical and Instrumentation and Controls"

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

aging analyses.

2.1.3 Scoping and Screening Program Review

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

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

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

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

criteria for the scoping and screening methodology review:

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

* 10 CFR 54.4(b) as to identification of the_ intended functions of plant systems and

structures within the scope of the Rule

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

to identify plant SCs subject to an AMR

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

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

sections:

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

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

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

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

The staff conducted a scoping and screening methodology audit at JAFNPP in Oswego, New

York during the week of September 26-29, 2006. The audit focused on whether the applicant

had developed and implemented adequate guidance for the scoping and screening of SSCs by

the methodologies in the LRA and the requirements of the Rule. The staff reviewed

implementation of the project level guidelines and topical reports describing the applicant's

scoping and screening methodology. The staff discussed with the applicant details of the

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

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

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

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

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

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Analysis Report Supplement," and LRA Appendix.B, "Aging Management Programs and

Activities" and the training and qualification of the LRA development team. The staff reviewed

scoping and screening results reports for the main steam (MS) system and trenches, valve pits,

manholes, and duct banks for the applicant's appropriate implementation of the methodology

outlined in the administrative controls and for results consistent with the current licensing basis

(CLB) documentation.

2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and

Screening

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

documented in the audit report dated March 27, 2007, to verify whether the process for

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

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

appropriate consideration of CLB commitments and for adequate implementation of the

procedural guidance during the scoping and screening process.

2.1.3.1.1 Summary of Technical Information in the Application

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

renewal scoping and screening process:

0 updated final safety analysis report (UFSAR)

a -technical specifications- -..

* safety classification documents

* safety system function sheets

* fire hazards analysis

* safe shutdown analysis

• design-basis documents (DBDs)

" equipment database

" maintenance rule basis documents

" plant layout drawings and license renewal boundary drawings (LRBDs)

" station drawings

The applicant stated that it used this information to specify the functions of plant systems and

structures. It then compared these functions to the 10 CFR 54(a)(1)-(3) scoping criteria to

determine whether the plant system or structure function is within the scope of license renewal

and used these sources to develop the list of structures and components subject to an AMR.

The LRBDs show the systems within the scope of license renewal highlighted in color.

2.1.3.1.2 Staff Evaluation

Scopinq and Screening Implementation Procedures. As documented in the audit report, the

staff reviewed the applicant's scoping and screening methodology implementation procedures,

including license renewal project guidelines (LRPGs), license renewal project

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documents/reports (LRPDs), AMR reports (specifically AMMs - mechanical, AMEs - electrical,

and AMCs - structural), for consistency with the requirements of the Rule, the Standard Review

Plan for License Renewal (SRP-LR), and NEI 95-10.

The staff found the overall process for implementing 10 CFR Part 54 requirements included in

the LRPGs, LRPDs and AMRs consistent with the Rule and industry guidance. The staff found

guidance for identifying plant SSCs within the scope of the Rule, including guidelines for

identifying SC component types within the scope of license renewal subject to an AMR, in the

LRPGs, LRPDs and AMRs. The review of these procedures focused on the consistency of the

detailed procedural guidance with information in the LRA reflecting implementation of staff

positions in the SRP-LR, interim staff guidance documents, and the information in request for

additional information (RAI) responses dated November 22, 2006.

After reviewing the LRA and supporting documentation, the staff finds LRA Section 2.1

consistent with the scoping and screening methodology instructions. The applicant's

methodology has sufficiently detailed guidance for the scoping and screening implementation

process followed in the LRA.

Sources of Current Licensing Basis Information. For JAFNPP, system safety functions are

stated in safety classification documents, the Maintenance Rule SSC basis documents for each

system, and in DBDs for systems for which DBDs were written. The staff considered the safety

objectives in the UFSAR system descriptions and identified objectives meeting the

safety-related criterion of 10 CFR 54.4(a)(1) as system intended functions.

The staff reviewed the scope and depth of the applicant's CLB information to verify whether the

applicant's methodology had identified all SSCs within the scope of license renewal as well as

component types requiring AMRs. As defined in 10 CFR 54.3(a), the CLB applies NRC

requirements, written licensee commitments for compliance with, and operation within,

applicable NRC requirements, and plant-specific design bases docketed and in effect. The CLB

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

design-basis information in the most recent UFSAR, and licensee commitments in docketed

correspondence like licensee responses to NRC bulletins, generic letters, and enforcement

actions as well as commitments in NRC safety evaluations or licensee event reports.

During the audit, the staff reviewed the applicant's information sources and samples of such

information, including the UFSAR, DBDs, controlled plant reference drawings, LRBDs, and

Maintenance Rule information.

In addition, the applicant's license renewal process indicated additional potential sources of

plant information pertinent to the scoping and screening process, including licensing

correspondence, a fire hazards analysis, safety evaluations, and design documentation (e.g.,

engineering calculations and design specifications). The staff verified that the applicant's

detailed LRPGs required use of the CLB source information in developing scoping evaluations.

The component database is the applicant's primary repository for component safety

classification information. During the audit, the staff reviewed the applicant's administrative

controls for component database safety classification data. Plant administrative procedures

describe these controls and govern their implementation.

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Based on a review of the administrative controls and a sample of the component database

component safety classifications, the staff concluded that the applicant's measures to control

the integrity and reliability of component database safety classification data are adequate, and,

therefore, that the component database is a source of component data sufficiently controlled to

support scoping and screening evaluations.

During the staff's review of the applicant's CLB evaluation process, the applicant discussed with

the staff the incorporation of CLB updates and the process for adequate incorporation into the

license renewal process. The staff determined that the LRA Section 2.1 description of the CLB

and related documents of the scoping and screening process is consistent with SRP-LR

guidance. In addition, the staff reviewed technical reports supporting reliance on SSCs to

demonstrate compliance with safety-related criteria, nonsafety-related criteria, and regulation of

the five events specified in 10 CFR 54.4(a)(1)-(3). The applicant's LRPGs comprehensively

listed documents supporting scoping and screening evaluations. The staff found these design

documentation sources useful in reviewing the applicant's initial scope of SSCs for consistency

with the CLB.

2.1.3.1.3 Conclusion

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

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

applicant's scoping and screening methodology considers CLB information consistently with

SRP-LR and RG 1.188; 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 applicant's quality controls for adequate implementation of scoping and

screening methodologies in the LRA. Although it did not develop the LRA under a

10 CFR Part 50, Appendix B, QA program, the applicant used the following QA processes

during the LRA development:

" The applicant developed License Renewal Project Plan JAF-RPT-05-LRPO1 as the QA

guide implemented for LRA preparation.

" Written procedures governed implementation of the scoping and screening

methodology. A tracking system accounted for dates when procedures were originally

issued and subsequently revised.

* The applicant reviewed previous RAIs for whether the LRA addressed pertinent issues.

" The Offsite and Onsite Safety Review Committees reviewed the LRA prior to its

submission to the staff.

" The QA committee examined the license renewal procedures and documents for

whether the LRA was in accordance with 10 CFR 54.4.

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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 personnel, and information from the staff's review of the JAFNPP's quality audit

reports, the staff concludes that these QA activities meet current regulatory requirements and

add assurance that LRA development activities have been according to LRA descriptions.

2.1.3.3 Training

2.1.3.3.1 Staff Evaluation

The staff reviewed the applicant's training process for consistent and appropriate guidelines

and methodology for the scoping and screening activities.

The license renewal scoping and screening activities and LRA development were accomplished

by Entergy, Areva, and JAFNPP personnel trained under the License Renewal Project Plan,

which included training requirements for both corporate and onsite personnel and indicated the

level of training appropriate to each license renewal task.

Corporate level training of Entergy and Areva personnel required comprehension of license

renewal procedures, guidelines, formats, industrial documents, scoping, screening, and industry

guidance and regulations required for scoping and screening activities and LRA development.

As a training record the applicant developed a training check list of procedures and documents

studied and levels of knowledge expected from class attendance. Onsite level training ensured

a general understanding of the license renewal process and terminology so JAFNPP license

renewal personnel could evaluate license renewal documents for technical accuracy.

The staff reviewed completed qualification and training records of several of the applicant's

license renewal personnel and also reviewed completed check lists. The staff determined that

these records adequately document the required training for applicant personnel. Additionally,

after discussions with the applicant's license renewal personnel during the audit, the staff

verified that the applicant's personnel were knowledgeable about the license renewal process

requirements and specific technical issues within their areas of responsibility.

2.1.3.3.2 Conclusion

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

scoping and screening process and review of selected design documentation supporting the

process, the staff concludes that the applicant's personnel understood the requirements and

adequately implemented the scoping and screening methodology documented in the LRA. The

staff concludes that the license renewal personnel were adequately trained and qualified for

license renewal activities.

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2.1.3.4 Conclusion of Scoping and Screening Program Review

Based on its review of LRA Section 2.1, review of the applicant's detailed scoping and

screening implementation procedures, discussions with the applicant's LRA personnel, and

review of the scoping and screening audit results, the staff concludes that the applicant's

scoping and screening program is consistent with SRP-LR guidance and, therefore, acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1.1 describes the methodology for scoping SSCs pursuant to 10 CFR 54.4(a)

and the plant scoping process for systems and structures.

Specifically, the scoping process developed a list of plant systems and structures with intended

functions as the bases for their inclusion within the scope of license renewal (as defined in

10 CFR 54.4(b)) by comparison of the system or structure functions with 10 CFR 54.4(a)

criteria. The systems list was developed from the component database and the structures list

from the UFSAR, Maintenance Rule documentation, plant layout drawings, and

structure-specific system codes in the component database. As described by the applicant, 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 based on component

functions.

Finally, the applicant evaluated the components in the systems and stFuctures within the scope

of license renewal. The LRBDs depicted the in-scope system boundary of SCs subject to

AMRs. The following sections address the applicant's scoping methodology as described in the

LRA.

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

2.1.4.1.1 Summary of Technical Information in the Application

LRA Section 2.1 .1.1 describes the 10 CFR Part 54 scoping methodology as to

10 CFR 54.4(a)(1 ) safety-related criteria, stating that systems and structures with safety

functions as defined by 10 CFR 54.4(a)(1) are within the scope of license renewal. Intended

functions for mechanical systems and structures were based on applicable plant licensing and

design documents including the UFSAR, technical specifications, safety system function

sheets, the fire hazards analysis, the safe shutdown analysis, DBDs, Maintenance Rule basis

documents, and various station drawings as required. The applicant also confirmed that all

plant conditions of normal operation, abnormal operational transients, design-basis accidents,

internal and external events, and natural phenomena for which the plant must be designed had

been considered for license renewal scoping under 10 CFR 54.4(a)(1)(i) through (iii) criteria.

Corporate and site procedures control the component and structure quality classifications.

Further, the applicant's definition of an SSC as safety-related is the same in 10 CFR 54.4 with

the exception of the guidelines for offsite exposures. Section 54.4 of 10 CFR refers to

10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), and 10 CFR 100.11 dose guidelines. The exposure

guidelines of 10 CFR 50.34(a)(1) do not apply because the construction permit was issued

before January 10, 1997. For plants (including JAFNPP) with construction permits issued

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before January 10, 1997, 10 CFR 50.34(a)(1) refers to the guidelines of 10 CFR Part 100,

which are included in the applicants definition. The exposure guidelines of 10 CFR 50.67(b)(2)

address the alternate source term, which the applicant has credited in the refueling accident

analysis. The applicant reviewed the systems and components credited in this limited use of

10 CFR 50.67 for inclusion within the scope of license renewal.

2.1.4.1.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied upon

to remain functional during and following a design basis event (DBE) to ensure (a) the integrity

of the reactor coolant pressure boundary, (b) the ability to shut down the reactor and maintain it

in a safe shutdown condition, or (c) the ability to prevent or mitigate the consequences of

accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1),

10 CFR 50.67(b)(2), or 10 CFR 100.11.

As to identification of DBEs, SRP-LR Section 2.1.3 states:

The set of DBEs as defined in the Rule is not limited to Chapter 15 (or

equivalent) of the UFSAR. Examples of DBEs that may not be described in this

chapter include external events, such as floods, storms, earthquakes, tornadoes,

or hurricanes, and internal events, such as a high energy line break. Information

regarding DBEs as defined in, 10 CFR 50.49(b)(1) may be found in any chapter

of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or

license'conditions within the CLB. These sources should also be reviewed to -..

identify SSCs relied upon to remain functional during and following DBEs (as

defined in 10 CFR 50.49(b)(1)) to ensure the functions described in

10 CFR 54.4(a)(1).

The applicant scoped SSCs for the 10 CFR 54.4(a)(1) criterion with the LRPGs, piping and

instrumentation diagrams (P&IDs), and other information sources as guidance in the

preparation, review, verification, and approval of the scoping evaluations for adequate scoping

results.

The staff reviewed these guidance documents for the applicant's evaluation of safety-related

SSCs, and sampled the applicant's scoping reports for methodology implemented in

accordance with those written instructions. In addition, the staff discussed the methodology and

results with the applicant's personnel responsible for these evaluations. Specifically, the staff

reviewed a sample of the license renewal scoping results for the MS and high-pressure coolant

injection (HPCI) systems and for the structural components (e.g., trenches, valve pits, manhole,

and duct bank structures) for additional assurance that the applicant had implemented its

scoping methodology adequately as to 10 CFR 54.4(a)(1). The staff verified that the scoping

results for each of the sampled systems were consistent with the methodology, that the SSCs

performing intended functions were credited, and that the bases for the results and intended

functions were described adequately. The staff verified that the applicant had used pertinent

engineering and licensing information to credit SSCs required to be within the scope of license

renewal in accordance with 10 CFR 54.4(a)(1) criteria.

To facilitate the identification of SSCs within the scope of license renewal according to

10 CFR 54.4(a) criteria, the applicant developed a license renewal information system (LRIS)

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with detailed design description information about all plant systems and structures and their

relevant functions and developed a list of safety-related SCs initially using the list in the

component database. The applicant used component database safety-classification fields to

consider systems or structures with safety-related components for inclusion within the scope of

the license renewal. SC1 component safety classification fields corresponded to

10 CFR 54.4(a) criteria and the SCI database safety-classification and related plant system

drawings were the applicant's starting points for specific components required to meet the

10 CFR 54.4(a)(1) criterion.

During the audit, the applicant described the process for evaluating components classified as

safety-related with no safety-related intended function. As part of the process, the applicant

stated, safety classifications of several components were re-evaluated to reconcile differences

between scoping determinations and facility database or CLB information. The applicant

evaluated safety-related components not performing intended functions and described explicitly

in the LRPDs the rationale for their exclusion from the scope of license renewal. The applicant

further evaluated the component database for components classified as safety-related but

performing no safety-related functions for verification that the CLB does not credit them for

such functions. Such verifications are documented in the scoping evaluations in the license

renewal results document.

The staff reviewed the safety classification criteria for consistency between the CLB and the

Rule definitions and the applicant's evaluation of the differences between the Rule definition

and the site-specific definition of "safety-related" for whether the applicant addressed

adequately all SSCs potentially meeting 10 CFR 54.4(a)(1) requirements. The applicant -

documented this evaluation in the LRA and in its onsite LRPDs. As part of license renewal

development, the applicant stated, the site-specific definition of "safety-related" was nearly

identical to the Rule definition with the following exception:

The CLB definition regarding potential off-site exposure limits refers to

10 CFR 50.100 whereas the rule also references comparable guidelines in

10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), and 10 CFR Part 100 respectively.

During the audit, the staff reviewed the applicant's evaluation of the Rule and CLB definitions as

to 10 CFR 54.4(a)(1). Based on this review, the staff verified that 10 CFR 50.34(a)(1) does not

apply because it covers construction permit applications since January 10, 1997. For such a

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

applicants definition. In addition, the applicant has amended its operating license to allow use of

an alternative source term for fuel handling accident analysis in accordance with 10 CFR 50.67.

The change to 10 CFR 50.67 dose limits does not affect the applicant's safety classification

definition; however, the applicant included all SSCs within the scope of license renewal as a

result of its use of the alternative source term. The staff reviewed the applicant's evaluation and

discussed it with the applicant's license renewal team. The staff determined that the applicant

adequately evaluated the differences between the applicant's definition and the Rule definition

of "safety-related" and that these differences did not cause any components to be considered

safety-related beyond those in the CLB.

2.1.4.1.3 Conclusion

Based on this sample review, discussions with the applicant, and review of the applicant's

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scoping process, the staff determines that the applicant's methodology for identifying systems

and structures meets 10 CFR 54.4(a)(1) scoping criteria and, therefore, is acceptable.

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

2.1.4.2.1 Summary of Technical Information in the Application

LRA Section 2.1.1.2 describes the scoping methodology as to 10 CFR 54.4(a)(2)

nonsafety-related criteria. The applicant's 10 CFR 54.4(a)(2) scoping methodology was based

on guidance from RG 1.188. The applicant's evaluation of the impacts of nonsafety-related

SSCs that met 10 CFR 54.4(a)(2) criteria used two major categories: (1) functional failure and

(2) physical failure. Summary descriptions of these two categories follow:

Functional Failure of Nonsafety-Related SSCs. SSCs required to perform functions in support

of safety-related components were classified as safety-related and within the scope of license

renewal in accordance with 10 CFR 54.4(a)(1). The applicant reviewed engineering and

licensing documents (UFSAR, Maintenance Rule scoping documents, and DBDs) for

exceptions included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

For the few exceptions of nonsafety-related components that must support safety functions,

LRA Section 2.3 describes the system intended functions and includes the components in the

appropriate AMRs.

Physical Failures of Nonsafety-Related SSCs. The applicant evaluated the impact of physical

failures of nonsafety-related SSCs within the scope of license renewal in-accordance with

10 CFR 54.4(a)(2) under the following two categories:

(1) Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The applicant

evaluated certain nonsafety-related components and piping outside the safety class

pressure boundary required to be structurally sound to maintain the pressure boundary

integrity of safety-related piping. These components perform a structural support

function. For piping in this structural boundary, pressure integrity is not required (except

for spatial interaction between nonsafety-related and safety-related SSCs); however,

piping within the safety class pressure boundary depends on the structural boundary

piping and supports for the system to fulfill its safety function.

For JAFNPP, the "structural boundary" is defined as the portion of a piping system

outside the safety class pressure boundary yet relied upon for its structural support.

(2) Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related

SSCs. The applicant considered various modes of spatial interactions when evaluating

potential spatial interaction between nonsafety-related systems and safety-related SSCs

and addressed them in the following categories:

physical impact (e.g., seismic Class Il/I) or flooding

pipe whip, jet impingement, or harsh environment from piping rupture

damage due to leakage or spray from nonsafety-related SSCs.

As documented in the audit report, the results of the applicant's evaluation of nonsafety-related

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SSCs affecting safety-related SSCs were incorporated into the license renewal project report,

which describes the 10 CFR 54.4(a)(2) review and the AMR of nonsafety-related systems and

components affecting safety-related systems. These results, described in LRA Sections 2.1.1.2

and 2.3.3.14, were input to the scoping and screening process.

2.1.4.2.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs the

failure of which could prevent satisfactory performance of safety-related SSCs relied upon to

remain functional during and following a DBE to ensure (a) the integrity of the reactor coolant

pressure boundary, (b) the ability to shut down the reactor and maintain it in a safe shutdown

condition, or (c) the ability to prevent or mitigate the consequences of accidents that could

cause offsite exposures comparable to those of 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or

10 CFR 100.11.

RG 1.188, Revision 1, "Standard Format and Content for Applications to Renew Nuclear Power

Plant Operating Licenses," dated September 2005, endorses the use of NEI 95-10, Revision 6,

for methods the staff considers acceptable for compliance with 10 CFR Part 54 in preparing

license renewal applications. NEI 95-10, Revision 6, addresses the staff positions on

10 CFR 54.4(a)(2) scoping criteria, nonsafety-related SSCs typically identified in the CLB,

consideration of missiles, cranes, flooding, high-energy line breaks, nonsafety-related SSCs

connected to safety-related SSCs, nonsafety-related SSCs in proximity of safety-related SSCs,

and the mitigative and preventive options in nonsafety-related and safety-related SSCs

interactions. - . . . .. . . . . . .....

The staff states that applicants should not consider hypothetical failures but rather base their

evaluation on the plant's CLB, engineering judgement and analyses, and relevant operating

experience, describing operating experience as all documented plant-specific and industry-wide

experience useful in determining the plausibility of a failure. Documentation would include NRC

generic communications and event reports, plant-specific condition reports, such industry

reports as safety operational event reports, and engineering evaluations.

The staff reviewed LRA Sections 2.1.1.2 and 2.3.3.14, where the applicant described the

scoping methodology for nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). In

addition, the staff reviewed the 10 CFR 54.4(a)(2) license renewal project report prepared by

the applicant as described in Safety Evaluation Report (SER) Section 2.1.4.2.1. The applicant's

evaluations were in accordance with the guidance of NEI 95-10, Revision 6, on the treatment of

SSCs meeting 10 CFR 54.4(a)(2) criteria. SER Section 2.1.4.2.1 also describes the applicant's

evaluation of nonsafety-related SSCs meeting 10 CFR 54.4(a)(2) criteria based on "functional

failure" and "physical failure" categories.

Based on a review of the LRA information and the aging management report for

10 CFR 54.4(a)(2) criteria and discussions with the applicant during the audit, the staffs

evaluation as to the applicant's categories follows in detail.

The applicant evaluated 10 CFR 54.4(a)(2) SSCs with the four categories from the NRC

guidance to the industry on identification and treatment of such SSCs:

(1) Nonsafety-Related SSCs Required for Functions that Support Safety-Related SSCs -

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The nonsafety-related SSCs required to perform functions in support of safety-related

functions were classified as safety-related in the applicant's equipment database and

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

applicant's 10 CFR 54.4(a)(2) aging management report addresses this criterion. For

exceptions to this approach where nonsafety-related components are required to

support safety functions, the appropriate AMR included the equipment. Exceptions are

containment equipment drains, vacuum priming and air removal, and the offgas portion

of gas handling (all three support standby gas treatment (SGT)); fuel pool cooling and

cleanup (support secondary means of pool makeup); residual heat removal (RHR)

(nonsafety-related portions support fuel pool cooling); condensate storage (supports

emergency core cooling system (ECCS)); and MS leak collection system. These

systems classified as nonsafety-related are required to perform a functions to support

safety-related functions and were included within the scope of license renewal in

accordance with 10 CFR 54.4(a)(2). The staff found that the applicant had implemented

an acceptable method for scoping of nonsafety-related systems performing functions

that support safety-related intended functions.

(2) Nonsafety-Related Systems Connected to and Structurally Supporting Safety-Related

SSCs - To identify the nonsafety-related SSCs directly connected to and required to be

structurally sound to maintain the integrity of safety-related SSCs, the applicant has

used a bounding approach (described in NEI 95-10, Appendix F), a seismic analysis,

and engineering judgment. The applicant reviewed each mechanical system

safety-related to nonsafety-related interface for components located between the

. interface-and the structural boundary or equivalent anchor (if used). The applicant

included all nonsafety-related SSCs within the scope of license renewal and within the

analyzed structural boundary in accordance with 10 CFR 54.4(a)(2). For structural

boundaries not indicated on drawings, the applicant included within the scope of license

renewal portions of the nonsafety-related SSCs beyond the safety-related SSCs to the

first equivalent anchor or seismic anchor. The LRA also indicates that if the structural

boundary for the interface of nonsafety-related and safety-related could not be

determined the nonsafety-related SSCs were included to a point beyond the interface to

a base-mounted component, flexible connection, or the end of the piping run in

accordance with NEI 95-10, Appendix F, guidance describing the use of "bounding

criteria" for determining the portion of nonsafety-related SSCs to be included within the

scope of license renewal. This method assured inclusion of the nonsafety-related piping

systems in the design-basis seismic analysis within the scope of license renewal. The

applicant's license renewal 10 CFR 54.4(a)(2) aging management report depicts these

nonsafety-related systems and components at nonsafety-related/safety-related

boundaries. This report also lists the AMR results of the component types with the

corresponding intended functions, materials, environments, aging effects, and

programs.

As to the use of equivalent anchors, staff discussions with the applicant's project team

during the audit revealed that equivalent anchors, flexible connections, and buried piping

were not used. Additionally, LRA Section 2.1.2.1.2 and the license renewal

10 CFR 54.4(a)(2) aging management report further confirm that its evaluation of each

mechanical system for safety-related to nonsafety-related interfaces and the first

structural boundary including seismic anchors, the bounding approach, was based on

the guidance of NEI 95-10, Appendix F.

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(3) Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related

SSCs - As reported in SER Section 2.1.4.2.1, the applicant considered physical impact

or flooding; pipe whip, jet impingement, or harsh environments; and fluid leakage or

spray when evaluating the potential for spatial interactions between nonsafety-related

systems and safety-related SSCs. The applicant used a spaces approach for scoping of

nonsafety-related systems with potential spatial interaction with safety-related SSCs

focused on the interaction between nonsafety-related and safety-related SSCs located

in the same space. A "space" was defined as a room or cubicle separated from other

spaces by substantial objects (e.g., walls, floors, and ceilings). The space was defined

to limit any potential interaction between nonsafety-related and safety-related SSCs to

the space.

As related to physical impact or flooding, and as described in the LRA, the applicant considered

situations where nonsafety-related supports for nonseismic (including seismic Il/I) piping

systems and electrical conduit and cable trays with potential for spatial interaction with

safety-related SSCs are included within the scope of license renewal per 10 CFR 54.4(a)(2) and

subject to an AMR. Civil/structural aging management reports address these supports and

components as commodities. In the applicant's earthquake experience there are no

occurrences of welded steel pipe segments falling. The applicant concluded that, as long as the

effects of aging on piping system supports are managed, falling of piping systems is not

plausible except if due to flow-accelerated corrosion and the piping section itself is not within

the scope for 10 CFR 54.4(a)(2) due to a physical impact hazard. The applicant evaluated

missiles that could be generated from internal or external events like failure of rotating

equipment. The nonsafety-related design features which protect safety-related*SSCs from such

missiles are within the scope of license renewal.

In addition, the applicant evaluated overhead-handling systems for structural failure that could

cause damage to any system and prevent the accomplishment of a safety function.

Nonsafety-related overhead-handling equipment determined to have a possible impact on

safety-related SSCs was included within the scope of license renewal.

As to pipe whip, jet impingement, and harsh environment, the applicant evaluated

nonsafety-related portions of high-energy lines against 10 CFR 54.4(a)(2) criteria. The

applicant's evaluation was based on a review of the UFSAR and relevant site documentation.

The applicant's high-energy systems were evaluated for component parts of safety-related

high-energy lines that can affect safety-related equipment.

If the applicant's high-energy line break analysis assumed that a nonsafety-related piping

system would not fail or assumed failure only at specific locations, that piping system (i.e.,

piping, equipment and supports) was included within the scope of license renewal per

10 CFR 54.4(a)(2) criteria and subject to an AMR for reasonable assurance that those

assumptions remain valid through the period of extended operation. Also, as addressed in the

LRPD for 10 CFR 54.4(a)(2) review, the applicant studied the reference documents with

high-energy line break analysis for inside as well as outside containment and indicated

high-energy lines for the MS, HPCI, reactor core isolation cooling (RCIC), core spray (CS), and

reactor water clean-up systems. Many of these systems were safety-related and included within

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

nonsafety-related high-energy lines with potential interaction.with safety-related SSCs were

included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

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For spray or leakage effects, the applicant evaluated moderate- and low-energy systems with

the potential for spatial interactions of spray and leakage. Nonsafety-related systems and

nonsafety-related portions of safety-related systems with the potential for spray or leakage that

could prevent safety-related SSCs from performing required safety functions were considered

within the scope of license renewal. The applicant used a "spaces" approach for

nonsafety-related SSCs located within the same space as safety-related SSCs. As described in

the LRA, a space is a room or cubicle separated from other spaces by substantial objects (e.g.,

walls, floors, and ceilings). The space was defined to limit any potential interaction between

nonsafety-related and safety-related SSCs to the space. The applicant.documented in its

scoping results (license renewal document (LRD)) report the evaluation of each mechanical

system for potential spatial interaction with safety-related SSCs as documented in the staff

audit report. After documenting the mechanical systems, the applicant evaluated system

functions for whether the system contained fluid, air, or gas. Based on spray or leakage and

operating experience, the applicant excluded nonsafety-related SSCs containing air or gas from

the scope of license renewal. The applicant then evaluated the mechanical systems for

components located within safety-related structures. Those liquid-filled systems with

components located within safety-related structures then were evaluated for components

located within spaces containing safety-related SSCs. Nonsafety-related SSCs containing fluid

and located within spaces containing safety-related SSCs, were included within the scope of

license renewal.

Protective features (e.g., whip restraints, spray shields, supports, missile or flood barriers)

preventing physical impact and fluid leakage, spray, or flooding are installed to protect

safety-related SSCs against spatial interaction with-nonsafety-related SSCs. Such protective

features credited in the plant design were included within the scope of license renewal and are

subject to an AMR.

2.1.4.2.3 Conclusion

Based on its review, the staff determines that the applicant's methodology for identifying

systems and structures meets 10 CFR 54.4(a)(2) scoping criteria and, therefore, is acceptable.

This determination is based on a review of sample systems, discussions with the applicant, and

review of the applicant's scoping process.

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

2.1.4.3.1 Summary of Technical Information in the Application

LRA Section 2.1.1.3 describes the methodology for identifying SSCs within the scope of license

renewal. Mechanical systems and structures that perform fire protection (FP), anticipated

transient without scram (ATWS), or station blackout (SBO) intended functions were included

within the scope of license renewal. LRA Sections 2.3 and 2.4 indicate mechanical systems and

structures with 10 CFR 54.4(a)(3) intended functions. For example, LRA Section 2.3.2.2 states

that the CS system has a 10 CFR 54.4(a)(3) intended function. The CS system is credited in

the 10 CFR Part 50 Appendix R safe shutdown capability analysis (10 CFR 50.48). LRA

Section 2.4.3 states that the radioactive waste building has one 10 CFR 54.4(a)(3) intended

function. The radioactive waste building houses equipment credited for FP (10 CFR 50.48). All

electrical and instrumentation and control (I&C) systems and electrical equipment in mechanical

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systems were included within the scope of license renewal.

Fire Protection. LRA Section 2.1.1.3.1, "Commission's Regulations for Fire Protection

(10 CFR 50.48)," describes the scoping of mechanical systems and structures required to

demonstrate compliance with the FP requirements in 10 CFR 50.48. From its CLB the applicant

indicated the mechanical systems and structures relied upon to meet 10 CFR Part 50

Appendix R and 10 CFR 50.48 requirements. Mechanical systems and structures credited with

FP and fire detection and mitigation in areas with safety-related equipment and equipment

credited with safe shutdown in a fire were included within the scope of license renewal.

Environmental Qualification (EQ). LRA Section 2.1.1.3.2, "Commission's Regulations for

Environmental Qualification (10 CFR 50.49)," describes the 10 CFR 50.49 EQ requirements. All

electrical and I&C systems and electrical equipment in mechanical systems were included

within the scope of license renewal. Consequently, environmentally-qualified equipment was

included within the scope of license renewal.

Pressurized Thermal Shock. These requirements do not apply to JAFNPP, a boiling-water

reactor.

Anticipated Transient Without Scram. LRA Section 2.1.1.3.4, "Commission's Regulations for

Anticipated Transients Without Scram (10 CFR 50.62)," describes the scoping of mechanical

systems and structures required to demonstrate compliance with 10 CFR 50.62 ATWS

requirements. Mechanical systems and structures that perform 10 CFR 50.62 intended

functions were included within the scope of license renewal.- -

Station Blackout. LRA Section 2.1.1.3.5, "Commission's Regulations for Station Blackout

(10 CFR 50.63)," describes the scoping criteria. The applicant developed a four-hour coping

analysis to address 10 CFR 50.63 requirements. Based on the its CLB for SBO, the applicant

determined system intended functions in support of 10 CFR 50.63 requirements. Based on staff

guidance in SRP-LR Section 2.5.2.1.1, the applicant conservatively included certain switchyard

components required to restore offsite power within the scope of license renewal even though

those components are not relied on in safety analyses or plant evaluations for functions that

demonstrates compliance with SBO regulations (10 CFR 50.63). The applicant uses a bounding

approach to scoping for electrical equipment. Onsite electrical systems and electrical equipment

in mechanical systems are included by default within the scope of license renewal.

Consequently, electrical equipment supporting 10 CFR 50.63 requirements was included within

the scope of license renewal.

2.1.4.3.2 Staff Evaluation

The staff reviewed the applicant's approach to indicating mechanical systems and structures

relied upon to perform functions related to the four regulated BWR events as described in

10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the

applicant, reviewed the documentation developed to support the approach, and evaluated a

sample of the mechanical systems and structures indicated as within the scope of

10 CFR 54.4(a)(3) criteria.

The applicant's implementing procedures describe the process for indicating systems and

structures within the scope of license renewal, stating that all mechanical systems and

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structures performing intended functions for 10 CFR 54.4(a)(3) were included within the scope

of license renewal and that the scoping results are in the applicants scoping results report,

which also describes the information sources, including the UFSAR, the system safety function

sheets, and the system design basis documents, for mechanical systems and structures

credited for response to regulated events.

Fire Protection. The LRD states that the applicant used the Fire Hazard Analysis, Fire

Protection, and Appendix R Program; the Safe Shutdown Capability Reassessment; and the

Technical Requirements Manual to indicate mechanical systems and structures included within

the scope of license renewal for FP. The LRD shows the mechanical systems included within

the scope of license renewal because they perform 10 CFR 50.48 intended functions,

summarizes scoping results for mechanical systems, and identifies 26 mechanical systems with

one or more 10 CFR 50.48 intended functions. The report also indicates structures within the

scope of license renewal because they perform 10 CFR 50.48 functions and summarizes

scoping results for ten structures with one or more 10 CFR 50.48 intended functions. A

summary of the scoping results for structures indicates 14 with one or more 10 CFR 50.48

intended functions. The staff reviewed the Fire Hazard Analysis, Fire Protection, and

Appendix R Program; the Safe Shutdown Capability Reassessment; the Technical

Requirements Manual; and the results reports to verify the SSCs to be included within the

scope of license renewal for FP and determined that the methodology had been appropriate.

Environmental Qualification. Using a bounding scoping approach for electrical equipment, the

applicant included by default all electrical systems and all electrical equipment in mechanical

systems, including equipment relied upon to perform functions that demonstrate compliance

with EQ regulations, within the scope of license renewal.

As documented in the audit report, for the EQ-regulated event, after reviewing the LRA and the

applicant's implementation procedures, results reports, and the master equipment list for EQ

components to verify that the applicant had indicated SSCs included within the scope of license

renewal for EQ, the staff determined that the methodology had been applied appropriately.

Anticipated Transient Without Scram. The applicant's scoping results report indicates the

mechanical systems included within the scope of license renewal because they perform

10 CFR 50.62 intended functions. For example, the control rod drive (CRD) system has one

intended function, alternate rod insertion during an ATWS. The report summarizes the scoping

results for mechanical systems, indicates that the CRD and standby liquid control (SLC)

systems perform 10 CFR 50.62 intended functions, and includes one structure within the scope

of license renewal because it performs a 10 CFR 50.62 intended function. The reactor building

was included within the scope of licensee renewal because it houses equipment credited for

ATWS.

Station Blackout. The applicant's scoping results report states that mechanical systems and

structures credited with the four-hour coping duration were included within the scope of license

renewal. The applicant conservatively included within the scope of license renewal switchyard

components required to restore offsite power even though those components are not relied on

in safety analyses or plant evaluations to perform functions demonstrating compliance with

SBO regulation (10 CFR 50.63). The report identified mechanical systems included within the

scope of license renewal because they perform 10 CFR 50.63 intended functions. For example,

the RCIC system has an intended function to provide makeup water to the reactor vessel during

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SBO. The report summarizes the scoping results for mechanical systems and indicates four

with one or more 10 CFR 50.62 intended functions. The report also indicates structures

included within the scope of license renewal because they perform 10 CFR 50.62 functions. For

example, the transformer/switchyard support structures have an intended function to support

equipment credited for SBO. The report summarizes the scoping results for structures and

indicates five structures with one or more 10 CFR 50.62 intended functions.

2.1.4.3.3 Conclusion

Based on the sample review, discussions with the applicant, and review of the applicant's

scoping process, the staff determines that the applicant's methodology for identifying systems

and structures is consistent with Interim Staff Guidance 2 (ISG-2) for meeting the requirements

of the SBO Rule (10 CFR 50.63) and; thus, has met 10 CFR 54.4(a)(3) scoping criteria and is,

therefore, acceptable.

2.1.4.4 Plant-Level Scoping of Systems and Structures

2.1.4.4.1 Summary of Technical Information in the Application

System and Structure Level Scopinq. As documented in the audit report, the applicant

documented its methodology for scoping SSCs in accordance with 10 CFR 54.4(a) in the

LRPGs, project documents, and aging management report. The applicant's approach to system

and structure scoping stated in the site guidance was consistent with the methodology

described in LRA Section 2.1.Particularly, the LRPG specifies-that-license renewal scoping

personnel use CLB documents to describe the system or structure including a list of functions it

is required to perform. Sources of information on the CLB for systems include the USAR,

DBDs, the component database, Maintenance Rule scoping reports, control drawings, and

docketed correspondence. The applicant then determined whether the system or structure

functions met 10 CFR 54.4(a) scoping criteria. The applicant documented the results of the

plant-level scoping process in accordance with the LRPGs.

The systems and structures scoping report contained in the LRDs provided these results.

Information in the results report includes a structure or system description, the functions it

performs, system realignment (as applicable), intended functions, the 10 CFR 54.4(a) scoping

criteria met, references, and the bases for the classification of the system or structure intended

functions. During the scoping methodology audit, the staff reviewed a sampling of LRD reports

and concluded that the applicant reported scoping results in an appropriate level of detail to

document the scoping process.

Based on a review of the LRA, the scoping and screening implementation procedures, and a

sampling review of system and structure scoping results during the methodology audit, the staff

finds the applicant's scoping methodology for systems and structures meeting the requirements

of 10 CFR 50.54. In particular, the staff determines that the applicant's methodology reasonably

indicates systems and structures within the scope of license renewal and their intended

functions.

Component Level Scopina. After indicating the systems and structures within the scope of

license renewal, the applicant reviewed mechanical systems and structures for components in

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each system and structure within the scope of license renewal. The structural and mechanical

components that supported intended functions were considered within the scope of license

renewal and screened to determine whether an AMR was required. All electrical components

within the scope of mechanical and electrical systems were included within the scope of license

renewal as commodity groups. The applicant considered three component classifications during

this stage of the scoping methodology: mechanical, structural, and electrical. The component

database and controlled plant drawings comprehensively listed plant components. The

applicant used component type and unique component identification numbers for each

component within the scope of license renewal and subject to an AMR.

Commodity Groups Scopinq. Initially the applicant included all electrical components within the

scope of mechanical and electrical systems as separated commodity groups. The applicant

screened out many electrical component types considered active according to RG 1.188 and

the SRP-LR as not meeting the passive criteria and not subject to an AMR. LRA Section 2.1.2.3

describes the commodity groups for evaluating all in-scope electrical components subject to an

AMR.

Structural components were grouped as structural commodity types based on materials of

construction. LRA Section 2.1.2.2.1 shows the various structural commodity groups including:

" steel

* threaded fasteners

" concrete

* fire- barriers

Insulation. LRA Section 2.4.4, "Bulk Commodities," states that insulation may have the specific

intended functions of (1) controlling heat load during design-basis accidents (DBAs) in areas

with safety-related equipment or (2) maintaining integrity so falling insulation does not damage

safety-related equipment (reflective metallic-type reactor vessel insulation). As such insulation

is included within the scope of license renewal as a commodity group in applications where it

performs either intended function.

Consumables. LRA Section 2.1.2.4, "Consumables," addresses short-lived items. The applicant

used the guidance in SRP-LR Table 2.1-3 to evaluate consumables, dividing them into the

following four categories for purposes of license renewal: (a) packing, gaskets, component

seals, and O-rings, (b) structural sealants, (c) oil, grease, and filters, and (d) system filters, fire

extinguishers, fire hoses, and air packs.

Group (a) subcomponents are not relied upon to form a pressure-retaining function and,

therefore, not subject to an AMR. Group (b) subcomponents are structural sealants for

structures within the scope of license renewal that require an AMR. Group (c) subcomponents

are periodically replaced and monitored for condition according to plant procedures and,

therefore, not subject to an AMR. Group (d) consumables are subject to replacement based on

National Fire Protection Association (NFPA) standards according to plant procedures and,

therefore, not subject to an AMR.

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant's methodology for scoping plant systems and components for

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consistency with 10 CFR 54.4(a). The applicant documented the methodology for identifying

mechanical SSCs within the scope of license renewal in the license renewal results report and

plant level scoping results in LRA Tables 2.2-1a for mechanical systems and 2.2-3 for

structures. The scoping process defined the entire plant in terms of systems and structures.

Specifically, the applicant used the LRPGs to indicate the systems and structures subject to

10 CFR 54.4 review, to describe the processes for recording the results of the review, and to

determine whether the system or structure performed intended functions consistent with

10 CFR 54.4(a) criteria. The process was completed for all systems and structures to address

the entire plant. The applicant's personnel initially reviewed systems and structures in the CLB.

The staff noted that a system or structure was presumed to be within the scope of license

renewal if it performed one or more safety-related functions or met other scoping criteria per the

Rule as determined by CLB review. Mechanical and structural component types that support

intended functions and all component types in electrical systems were considered within the

scope of license renewal and placed in commodity groups. The applicant screened electrical

commodity groups further to determine whether they required An AMR. The staff found no

discrepancies with the applicant's methodology.

The staff reviewed the applicant's methodology for generating commodity groups. The LRDs

indicate separate commodity groups for various mechanical, structural, and electrical

components. The staff reviewed the commodity group level functions evaluated by the applicant

in accordance with 10 CFR 54.4(a). This evaluation determined whether the commodity group

was within the scope of license renewal. The staff found the methodology acceptable.

The staff reviewed the scoping process results documented in the scoping results report in

accordance with the LRPGs. This documentation adequately described how the system or

structure are meeting its 10 CFR 54.4(a) scoping criteria requirements. The staff also reviewed

a sample of the applicant's scoping documentation and concluded that it had a level of detail

appropriate to document the scoping process.

The staff reviewed the applicant's evaluation of plant insulation as documented in the license

renewal results report and the bulk commodities AMR. The applicant indicated insulation as

within the scope of license renewal and subject to an AMR based on the intended functions of

heat transfer reduction and structural or functional support to nonsafety-related SCs the failure

of which could prevent performance of safety-related functions. Both mirror and nonmirror

insulation were evaluated. The staff finds the applicant's methods and conclusions on insulation

acceptable.

The staff reviewed the scoping and screening of consumables and finds that the applicant

followed the process described in SRP-LR and appropriately categorized consumables in

accordance with the guidance. The applicant initially evaluated plant consumables for whether

any met the criteria requiring an AMR (e.g., structural sealants). Additionally, the applicant cited

all industry guidelines (e.g., NFPA standards) used as the basis for replacement of any item.

2.1.4.4.3 Conclusion

Based on its review of the LRA, mechanical system and structures results reports, scoping and

screening implementation procedures, and a sampling of system scoping results during the

audit, the staff concludes that the applicant's scoping methodology for plant SSCs, commodity

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groups, insulation, and consumables is acceptable. In particular, the staff determines that the

applicant's methodology reasonably identifies systems, structures, component types, and

commodity groups within the scope of license renewal and their intended functions.

2.1.4.5 Mechanical Component Scoping

2.1.4.5.1 Summary of Technical Information in the Application

LRA Section 2.1 describes the methodology for identifying mechanical system components

within the scope of license renewal. For mechanical systems, components that support system

intended functions are within the scope of license renewal. For mechanical system scoping, the

applicant defined a system as the collection of components in the component database

assigned to the system code. The applicant determined system intended functions by the

functions performed by those components. Definition of a system by database components is

generally consistent with Maintenance Rule scoping documents and safety classification

procedure. The applicant evaluated each mechanical system against 10 CFR 54.4 criteria to

determine which system components performed intended functions consistent with the scoping

criteria.

LRA Section 2.1.2.1.3, "Mechanical System Drawings," describes how the LRBDs are prepared

to indicate system portions that support system intended functions within the scope of license

renewal.

Boundary flags-are marked-with safety-to-nonsafety class-breaks to indicate system intended

function boundaries for system in-scope portions. Components within these boundary flags and

class breaks support system intended functions within the scope of license renewal.

Components subject to an AMR (i.e., passive, long-lived components that support system

intended functions) are highlighted with color coding to indicate which system AMR evaluated

the components. Drawings with only highlighting and no boundary flags indicate that all

components on the drawing support the system intended functions unless excluded by

safety-to-nonsafety class breaks.

2.1.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.1 and the guidance in LRPGs, LRDs, and aging management

reports to complete the review of mechanical scoping process. The program guidelines and

aging management reports state instructions for evaluating individual mechanical system

components by the scoping criteria. The applicant utilized CLB documents when determining

whether a system or component is within the scope of 10 CFR 54.4(a). Examples of these

sources included, but were not limited to, the UFSAR, Maintenance Rule database, separate

ATWS, EQ, FP and SBO documents, technical specifications, and SERs. Additional sources of

mechanical component information included the component database and individual system

flow diagrams.

The applicant evaluated mechanical system diagrams to create license renewal boundaries for

each system showing-the in-scope components and evaluated components supporting

safety-related functions or regulated events further during the screening process for whether

they should be subject to an AMR.

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Nonsafety-related components connected to safety-related components and providing structural

support at the safety/nonsafety interface or components the failure of which could prevent

satisfactory accomplishment of a safety-related function due to spatial interaction with

safety-related SSCs are included within the scope of license renewal and in the AMR for the

10 CFR 54.4(a)(2) evaluation but not specifically highlighted on the license renewal drawings.

As part of the applicant's verification process, the list of mechanical components within the

scope of license renewal was compared to the data in the LRIS and the component database to

confirm the scope of components in the system.

The staff reviewed the implementation guidance and the CLB documents for mechanical

system scoping and found the guidance and CLB source information acceptable to indicate

mechanical components and support structures in mechanical systems within the scope of

license renewal. The staff conducted detailed discussions with the applicant's license renewal

project management personnel, reviewed documentation of the scoping process, and assessed

whether the applicant had applied the scoping methodology outlined in the LRA and

implementation procedures appropriately and whether the scoping results were consistent with

CLB requirements. The staff found the applicant's procedural methodology consistent with the

description LRA Section 2.1 and the guidance of SRP-LR Section 2.1 and adequately

implemented.

Scoping Methodology for the Main Steam System. LRA Section 2.3.4.2, "Main Steam," states

the scoping and screening methodology results for SSCs within the nonsafety-related MS

system, which accomplishes the following scoping criteria of the Rule.

The MS system has the following 10 CFR 54.4(a)(1) intended functions:

• Main steam isolation valve (MSIV) and MS line drain valve isolation support

• Provision of steam to HPCI turbine

• Maintenance of reactor coolant pressure boundary (RCPB) integrity up to and including

the downstream MSIV

• MSIV leakage collection and release

" MS leak collection system isolation valve isolation support

* Maintenance of N2 pressure boundary in containment

° Maintenance of the boundary between the reactor cavity and the MS lines during

refueling, testing, and maintenance activities

The MS system has the following 10 CFR 54.4(a)(2) intended functions:

Support of MS leak collection system operation by nonsafety-related MS line piping

downstream of the MSIVs

Maintenance of nonsafety-related component integrity so no physical interaction with

safety-related components could prevent satisfactory accomplishment of a safety

function

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The MS system has the following 10 CFR 54.4(a)(3) intended functions:

" FP as credited in the 10 CFR Part 50 Appendix R safe shutdown analysis

(10 CFR 50.48)

" Provision of steam to the HPCI and RCIC turbines during SBO (10 CFR 50.63)

As part of the audit, the staff reviewed the applicant's methodology for indicating MS

mechanical component types meeting the scoping criteria as defined in the Rule. The staff also

reviewed the scoping methodology implementation procedures and discussed the methodology

and results with the applicant. The staff verified that the applicant had used pertinent

engineering and licensing information to determine the MS mechanical component type within

the scope of license renewal. As part of the review process, the staff evaluated each system

intended function of the MS system, the basis for inclusion of the intended function, and the

process for indicating the system components credited with intended functions. The staff

verified that the applicant had highlighted system P&IDs to develop the system boundaries in

accordance with procedural guidance. The applicant was knowledgeable about the process and

conventions for establishing boundaries as defined in the license renewal implementation

procedures. Additionally, the staff verified that the applicant independently had verified the

results in accordance with the governing procedures. Specifically, other license renewal

personnel knowledgeable about the system independently had evaluated the marked-up

drawings for accurate system intended functions. The applicant completed additional

cross-discipline verification and independent evaluation of the highlighted drawings before final

approval of thescoping,_

2.1.4.5.3 Conclusion

Based on its review of the LRA, scoping implementation procedures, and a sample of

mechanical component scoping results for the CS system, the staff concludes that the

applicant's methodology for identifying mechanical components within the scope of license

renewal meets 10 CFR 54.4(a) requirements.

2.1.4.6 Structural Component Scoping

2.1.4.6.1 Summary of Technical Information in the Application

LRA Section 2.1 describes the methodology for identifying structures within the scope of license

renewal. Initially the applicant identified all plant structures and SBO-related nonplant structures

and structure intended functions from CLB documents (e.g., the UFSAR, the Maintenance Rule

document for buildings and structures, safety classification procedures, the fire hazards

analysis, and the safe shutdown capability assessment). Structures with 10 CFR 54.4(a)

intended functions were included within the scope of license renewal and listed in LRA

Table 2.2-3, structures not within the scope of license renewal in LRA Table 2.2-4. LRA

Section 2.4 describes the scoping results for individual structures within the scope of license

renewal. LRA Section 2.4.3 describes various structures within the turbine building complex and

yard structures and their seismic classifications based on design requirements. For example,

manholes and duct banks were included within the scope of license renewal because they

support safety-related and nonsafety-related equipment within thescope of license renewal.

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2.1.4.6.2 Staff Evaluation

The staff reviewed the applicant's approach to identifying structures relied upon for functions

described in 10 CFR 54.4(a). In this review, the staff discussed the methodology with the

applicant, reviewed the supporting documentation, and evaluated the scoping results for

several structures within the scope of license renewal.

The LRPGs describe the applicant's process for identifying structures within the scope of

license renewal and state that all structures with intended functions must be included and

scoping results documented in the scoping results report, which lists all structures evaluated

and describes the procedures for identifying them by use of the plant UFSAR, Maintenance

Rule document, fire hazards analysis, and safe shutdown capability analysis.

The staff reviewed the applicant's implementation procedures and scoping results reports.

Structural scoping considered all plant buildings, yard structures, and SBO related nonplant

structures. The scoping results report specifies the intended function(s) for each structure

required for compliance with one or more 10 CFR 54.4(a) criteria. Structural component

intended functions were based on the guidance of NEI 95-10, and the SRP-LR. The applicant

determined structure evaluation boundaries by developing a complete description of each

structure as to its intended functions. The scoping results report documents a list. of structures,

evaluation results for the 10 CFR 54.4(a) criteria for each structure, a description of structural

intended functions, and source reference information for the functions.

The staff conducted detailed discussions with the- applicant's license renewal -team and

reviewed documentation pertinent to the scoping process. The staff assessed whether the

scoping methodology outlined in the LRA and procedures had been implemented appropriately

and whether the scoping results were consistent with CLB requirements. In these audit

activities the staff found no discrepancies between the methodology documented and the

implementation results.

2.1.4.6.3 Conclusion

Based on its review of the LRA, the applicant's detailed scoping implementation procedures,

and a sampling of structural scoping results, the staff concludes that the applicant's

methodology for identification of structural component types within the scope of license renewal

meets 10 CFR 54.4(a) requirements 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," describes the scoping process for electrical

systems and components. For purposes of system level scoping, plant electrical and I&C

systems were included within the scope of license renewal. Electrical and I&C components in

mechanical systems were included in the evaluation of electrical systems. LRA Section 2.1.1

refers to LRA Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and

Control Systems," which states that the default inclusion of plant electrical and I&C systems

within the scope of license renewal reflects the method used for the scoping of electrical

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systems, which is different from the methods used for mechanical systems and structures. The

applicant's approach to electrical and I&C components included components in the review

unless specifically screened out. When used with the plant spaces approach, this method

eliminated the need for unique identification of every component and its specific location and

gave assurance no component was excluded from an AMR.

2.1.4.7.2 Staff Evaluation

As documented in the audit report, the staff evaluated LRA Sections 2.1.1 and 2.5 and the

applicant's implementing procedures and aging management reports governing the electrical

scoping methodology. The scoping phase for electrical components began with the placement

within the scope of license renewal of all plant system electrical components and nonplant

electrical systems including switchyard components required for SBO. Switchyard components

required to restore offsite power also were included conservatively within the scope of license

renewal even though those components are not relied on in safety analyses or plant evaluations

for functions demonstrating compliance with SBO regulation (10 CFR 50.63). The staff

determined that the data sources for scoping included the component data base, the station

single line drawing, and the cable design procurement specifications. The staff reviewed

portions of the data sources and selected several examples of components for which the

applicant demonstrated the process for determining whether electrical components were within

the scope of license renewal.

2.1.4.7.3 Conclusion

Based on its review of the LRA, the applicant's detailed scoping implementation procedures,

and a sampling of electrical scoping results, the staff concludes that the applicant's

methodology for identification of electrical components within the scope of license renewal

meets 10 CFR 54.4(a) requirements and, therefore, is acceptable.

2.1.4.8 Conclusion for Scoping Methodology

Based on its review of the LRA and the scoping implementation procedures, the staff

determines that the applicant's scoping methodology is consistent with SRP-LR guidance and

has identified SSCs within the scope of license renewal in accordance with the requirements of

10 CFR 54.4(a)(1), (2), and (3). Therefore, the staff concludes that the applicant's methodology

meets 10 CFR 54.4(a) requirements.

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.

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2.1.5.1.1 Summary of Technical Information in the Application

LRA Section 2.1.2, "Screening Methodology," describes the method of identifying components

from in-scope systems and structures subject to AMRs. The screening consists of the following

steps:

Identification of long-lived or passive components for each in-scope mechanical system,

structure, and electrical commodity group

Identification of the license renewal intended function(s) for all mechanical and structural

component types and electrical commodity groups

Active components were screened out and, therefore, required no AMR. The screening process

also identified short-lived components and consumables. The short lived components are not

subject to an AMR. Consumables are a special class of items that include packing, gaskets,

component seals, O-rings, oil, grease, component filters, system filters, fire extinguishers, fire

hoses, and air packs. Structural sealants for structures were the only consumables within the

scope of license renewal requiring an AMR.

2.1.5.1.2 Staff Evaluation

Pursuant to 10 CFR 54.21, each LRA must contain an IPA that indicates SCs within the scope

of license renewal subject to an AMR. The IPA must indicate components that perform intended

Junctions without moving parts or a chang~e in co~nfiguration or propepries(passive) as well as

components not subject to periodic replacement after a qualified life or specified time period

(long-lived). The IPA describes and justifies the methodology for determining the passive and

long-lived SCs and demonstrates that the effects of aging on those SCs will be adequately

managed to maintain intended functions under all design conditions imposed by the

plant-specific CLB for the period of extended operation.

The staff reviewed the applicant's methodology to determine whether mechanical and structural

component types and electrical commodity groups within the scope of license renewal should

be subject to an AMR. The applicant implemented a process for determining which SCs were

subject to AMRs in accordance with 10 CFR 54.21 (a)(1). LRA Section 2.1.2 describes the

screening of component types and commodity groups within the scope of license renewal.

The screening process evaluated these in-scope component types and commodity groups to

determine which were long-lived and passive and, therefore, subject to an AMR. The staff

reviewed LRA Sections 2.3, 2.4, and 2.5, which presents the results of the process, and the

screening results reports for the MS system and structures.

The applicant discussed with the staff the processes for each discipline and provided

administrative documentation that describes the screening methodology. Specific methodology,

mechanical, electrical, and structural, is addressed below.

2.1.5.1.3 Conclusion

Based on its review of the LRA, the screening implementation procedures, and a sampling of

screening results, the staff determines that the applicant's screening methodology is consistent

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with SRP-LR guidance and capable of identifying passive, long-lived components within the

scope of license renewal and subject to an AMR. The staff determines that the applicant's

process for identifying component types and commodity groups subject to an AMR meets

10 CFR 54.21 requirements and, therefore, is acceptable.

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

LRA Section 2.1.2.1, "Screening of Mechanical Systems," describes the screening methodology

for passive and long-lived mechanical components and their support structures subject to

AMRs. License renewal drawings were prepared to indicate system portions that support

system intended functions within the scope of license renewal (except systems within the scope

of 10 CFR 54.4(a)(2) for physical interactions). In addition, the drawings show components

subject to an AMR. Boundary flags in conjunction with safety-to-nonsafety class breaks indicate

system intended function boundaries as noted on the drawings. All components within these

boundary flags and class breaks support system intended functions within the scope of license

renewal. Passive, long-lived components that support system intended functions are highlighted

to indicate that they are subject to an AMR.

2.1.5.2.2 Staff Evaluation

As documented in the audit report, the staff evaluated the mechanical screening methodology

in LRA 2.1.2.1, "Screening of-Mechanical Systems,".the LRDs, LRPGs,-and the aging -...

management reports. The mechanical system screening process began with the results from

the scoping process. The applicant reviewed each mechanical system flow diagram for passive

and long-lived components. To identify system components required to perform system

intended functions, the applicant initially listed mechanical system components based on

information from controlled system diagrams and the component database. The LRPGs and

LRDs explain in detail how (1) to determine system boundaries, (2) to indicate components

within specific flow paths required for intended functions, and (3) to determine system and

interdisciplinary interfaces (e.g., mechanical/structural, mechanical/electrical,

structural/electrical). After entering these components into the LRIS database, from the

component database the applicant confirmed that all system components had been considered.

Where the mechanical system flow diagrams of large vendor-supplied components (e.g.,

compressors, emergency diesel generators (EDGs)) were not in sufficient detail, the applicant

reviewed component drawings or vendor manuals as necessary for individual components.

The staff reviewed the results of the boundary evaluation, discussed it with the applicant, and

verified that mechanical system evaluation boundaries were established for each system within

the scope of license renewal. The applicant determined these boundaries by mapping the

pressure boundary of system-level license renewal intended functions onto the controlledsystem drawings. Mechanical component types were loaded into a scoping and screening

database for further review for inclusion of all component types. For a component type not

already in the LRIS, the applicant created a component type for use in the LRIS database. A

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preparer and an independent reviewer comprehensively evaluated the boundary drawings for

completeness and accuracy of the review results. As part of the evaluation, the applicant also

benchmarked system passive and long-lived components against previous LRAs for similar

systems.

As part of the audit, the staff reviewed the applicant's methodology for determining which SCs

meet the screening criteria of the Rule. The staff verified the applicant's implementation of the

staff SRP guidance and RG 1.188 in the screening. The staff found that the applicant had

developed sufficiently detailed procedures for the screening of mechanical systems, had

implemented those procedures, and had documented the results adequately in aging

management reports.

Additionally, the staff reviewed the screening of the MS and HPCI systems. The staff reviewed

the system intended functions and source documents for the system, the MS and HPCI P&IDs,

and the results documented in the aging management report. The staff found no discrepancies

with the evaluation and determined that the applicant adequately followed the process

documented in the LRDs and adequately documented the results in the aging management

reports.

2.1.5.2.3 Conclusion

Based on its review of the LRA, the screening implementation procedures, and a sample of MS

and HPCI systems screening results, the staff determines that the applicant's mechanical

component screening methodology is consistent with SRP-;LR guidance. The staff -concludes- -

that the applicant's methodology for identification of passive, long lived mechanical components

within the scope of license renewal and subject to an AMR meets 10 CFR 54.21(a)(1)

requirements; and, therefore, is acceptable.

2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

LRA Sections 2.1.2.2 and 2.4 describe the methodology for structural screening. LRA

Section 2.1.2.2 states that specific structural components are determined for each structure

within the scope of license renewal from the CLB (drawings, etc.). Passive and long-lived

structural components with intended functions were subject to an AMR. The applicant used the

SRP-LR and NEI 95-10, Appendix B, for the identification of passive structural components.

Structural components (e.g., door, gate, pipe support, strut, or siding) were categorized as

steel, threaded fasteners, concrete, fire barriers, elastomers, earthen structures, or

fluoropolymers and lubrite sliding surfaces. LRA Section 2.4 summarizes the screening results

for structures. For example, LRA Section 2.4.3 and LRA Table 2.4-3 summarize the screening

results for manholes and duct banks. Structural components common to all structures (e.g.,

mirror insulation) were categorized as bulk commodities. LRA Section 2.4.4 and LRA

Table 2.4-4 summarize the screening results for structural bulk commodities.

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2.1.5.3.2 Staff Evaluation

The staff reviewed the applicant's methodology for identifying structural components subject to

an AMR by 10 CFR 54.21(a)(1). In this review, the staff discussed the methodology with the

applicant, reviewed the supporting documentation, and evaluated the screening results for

several structures within the scope of license renewal.

As described in the audit report, the applicant's aging management reports details the

applicant's process for screening structural components subject to AMRs. The report states that

all passive and long-lived structural components that perform intended functions are subject to

AMRs. In addition, separate aging management reports describe the screening results for

major structural groups and bulk commodities.

The staff reviewed the applicant's methodology for structural screening described in the

noted LRA sections, the applicant's implementation guidance, and its aging management

reports. The applicant's screening, in accordance with its implementation guidance, recorded

pertinent structure design information, components, materials, environments, and aging effects.

The staff verified that the applicant had used the lists of passive SCs in the regulatory guidance

and supplemented them with additional items unique to the site or for which there were no

direct matches (i.e., material/environment combinations) to the generic lists.

The boundary for a structure was the entire building including base slabs, foundations, walls,

beams, slabs, and steel superstructure. The aging management reports indicate for each

-individual SCwhether the- component is subject to-an -AMR and identifies it-asa-component;-

component type (e.g., door, gate, anchor support, strut, or siding), or material. The applicant

discussed with the staff in detail that the screening methodology as well as the screening

reports for a selected group of structures.

2.1.5.3.3 Conclusion

Based on its review of the LRA, the applicant's detailed screening implementation procedures,

and a sampling of structural screening results, the staff concludes that the applicant's

methodology for identification of passive, long lived structural component types within the scope

of license renewal and subject to an AMR meets 10 CFR 54.21(a)(1) requirements; 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, "Screening of Electrical and Instrumentation and Control Systems,"

addresses the use of NEI 95-10, Appendix B, "Typical Structure, Component and Commodity

Groupings and Active/Passive Determinations for the Integrated Plant Assessment," which

identifies passive electrical commodities. The applicant cross-referenced electrical commodity

groups to the appropriate NEI 95-10 commodity, which identified the passive commodity

groups.

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The applicant determined that most electrical and I&C commodity groups are active and do not

require an AMR. Two passive electrical and I&C commodity groups meet the

10 CFR 54.21(a)(1)(i) criterion (components that perform intended functions without moving

parts or change in configuration):

° High-voltage insulators

° Cables and connections, bus, electrical portions of electrical and I&C penetration

assemblies

Additionally, the applicant considered the pressure boundary function of some electrical and

I&C components identified in NEI 95-10, Appendix B, (flow elements, vibration probes) in the

mechanical AMRs as applicable. Electrical components supported by structural commodities

(cable trays, conduit and cable trenches) were included. in the structural AMRs.

The applicant reviewed the passive electrical components for those replaced based on a

qualified life and therefore not subject to an AMR. The applicant determined that the

components included in the EQ of the Electric Components Program per 10 CFR 50.49 (EQ)

are replaced based on qualified life and, therefore are not subject to an AMR. The applicant

determined that there would be AMRs for the passive, non-EQ electrical and I&C components.

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant's methodology for electrical screening in LRA Section 2.1.2.3

_ and the applicant's irmpLementatiojn procedures and aging management reports. Theapplicant.

used the screening process described in these documents for electrical commodity groups

subject to AMRs. The applicant used the component database, the single-line drawings, and

cable procurement specifications as data sources of electrical and I&C components including

fuses-holders. The applicant determined there were no fuse-holders outside active devices and

subject to an AMR.

The applicant assembled a table of seven commodities determined to meet the passive criteria.

The seven commodities were grouped in accordance with NEI 95-10 as (1) cables and

connections, (2) electrical portions of penetration assemblies, (3) metal-enclosed buses, (4)

switchyard buses, (5) transmission conductors, (6) uninsulated ground conductors, and (7)

high-voltage insulators. These seven commodities were grouped further as (1) high-voltage

insulators and (2) cables and connections, buses, and electrical portions of electrical and I&C

penetration assemblies as described in the LRA. The applicant evaluated passive commodities

for whether they were subject to replacement based on a qualified life or specified time period

(short-lived) or long-lived. The applicant determined that the remaining passive, long-lived

components were subject to an AMR. The staff reviewed the screening of selected components

to verify the correct implementation of the LRPGs and aging management reports.

2.1.5.4.3 Conclusion

The staff reviewed the LRA, procedures, electrical drawings, and a sample of the screening

methodology results. The staff determined that the applicant's methodology was consistent with

the description in the LRA and with the applicant's implementing procedures. Based on a review

of information in the LRA, the applicant's screening implementation procedures, and a sampling

review of electrical screening results, the staff finds the applicant's methodology for

2-29
identification of electrical commodity groups subject to an AMR consistent with

10 CFR 54.21 (a)(1) and, therefore, acceptable.

2.1.5.5 Conclusion for Screening Methodology

Based on its review of the LRA and the screening implementation procedures, discussions with

the applicant's staff, and a sample review of screening results, the staff determines that the

applicant's screening methodology is consistent with the guidance of the SRP-LR and has

identified passive, long-lived components within the scope of license renewal and subject to an

AMR. The staff concludes that the applicant's methodology is consistent with the requirements

of 10 CFR 54.21(a)(1) and, therefore, acceptable.

2.1.6 Summary of Evaluation Findings

The information in LRA Section 2.1, the supporting information in the scoping and screening

implementation procedures and reports, the information presented during the scoping and

screening methodology audit, and the applicant's responses to the staff's RAIs dated

November 29, 2006, formed the basis of the staffs determination that the applicant's scoping

and screening methodology was consistent with the requirements of the Rule. Based on this

determination, the staff concludes that the applicant's methodology for identifying SSCs within

the scope of license renewal and SCs requiring an AMR is consistent with the requirements of

10 CFR 54.4 and 10 CFR 54.21(a)(1), and, therefore, 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 design basis events (DBEs), as required by

10 CFR 54.4(a)(1 ), systems and structures the failure of which could prevent satisfactory

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2), and systems

and structures relied on in safety analyses or plant evaluations to perform functions required by

regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary of Technical Information in the Application

LRA Tables 2.2-1a, 2.2-1b, and 2.2-3 list respectively plant mechanical systems, electrical and

I&C systems, and structures within the scope of license renewal. LRA Tables 2.2-2 and 2.2-4

list respectively plant mechanical systems and structures not within the scope of license

renewal. Based on the DBEs considered in the plant's CLB, other CLB information as 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.

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2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying systems and

structures within the scope of license renewal and subject to an AMR. The staff reviewed the

scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify

that the applicant properly implemented its methodology, the staff's review focused on the

implementation results shown in LRA Tables 2.2-1a, 2.2-1b, 2.2-2, 2.2-3, and 2.2-4, to confirm

that there were no omissions of plant-level systems and structures within the scope of license

renewal.

The staff determined whether the applicant properly identified the systems and structures within

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected

systems and structures that the applicant did not identify as falling within the scope of license

renewal to verify whether the systems and structures have any intended functions requiring

their inclusion within the scope of license renewal. The staff's review of the applicant's

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2,

"Plant-Level Scoping Results."

The staff sampled the contents of the UFSAR based on the systems and structures listed in

LRA Tables 2.2-1a, 2.2-1 b, 2.2-2, 2.2-3, and 2.2-4 to determine if there were any systems or

structures that may have intended functions within the scope of license renewal, as defined by

10 CFR 54.4, but were omitted from the scope of license renewal. The staff found no

omissions.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2 and the 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. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified in accordance with

10 CFR 54.4 the systems and structures that are 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:

0 reactor coolant system

0 engineered safety features

• auxiliary systems

a steam and power conversion systems

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive,

long-lived SOs 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.

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The staff's evaluation of the information in the LRA was the same for all mechanical systems.

The objective was to determine whether the applicant has identified, in accordance with

10 CFR 54.4, components and supporting structures for mechanical systems that appear to

meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's

screening results to verify that all passive, long-lived components were subject to an AMR in

accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections and component

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.

In addition, the staff developed a "Two-Tier Scoping Review Process" to evaluate

balance-of-plant (BOP) systems. There are 57 mechanical systems in the LRA among which 26

are BOP systems, that include most of the auxiliary systems and all the steam and power

conversion systems. The staff performed a two-tier scoping review for these BOP systems.

In the two-tier scoping review, the staff reviewed the LRA and UFSAR description focusing on

the system intended function to screen all the BOP systems into two groups based on the

following screening criteria:

" safety importance/risk significance

" potential for system failure to cause failure of redundant safety system trains

" operating experience indicating likely passive failures

• systems subject to omissions based on previous LRA reviews

Examples of the safety important/risk significant systems are the feedwater system, the

emergency diesel generator (EDG) system, and the service water (SW) system based on the

results of Individual Plant Examination (IPE) for JAFNPP.:An example of a system whose

failure could result in common cause failure of redundant trains is a drain system providing

flood protection. Examples of systems with operating experience indicating likely passive

failures include MS system, feedwater system, and SW system. Examples of systems with

identified omissions in previous LRA reviews include fuel pool cooling and cleanup system, and

makeup water sources to safety systems.

From the 26 BOP systems, the staff selected 16 systems for a Tier-2 (detailed) scoping review

as described above. For the remaining 10 BOP systems, the staff performed a Tier-1 (not

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requiring detailed boundary drawings) review of the LRA and UFSAR that would identify

apparent missing components for an AMR. However, Tier-2 requires the review of detailed

boundary drawings in accordance with SRP-LR Section 2.3. The following is a list of the

10 Tier-1 systems:

a auxiliary boiler and accessories

* city water

9 extraction steam

a feedwater heater vents and drains

• plumbing, sanitary and lab

* raw water treatment

* secondary plant drains

* steam seal

* turbine lube oil

* vacuum priming and air

The staff verified that there is no risk significant system in the above list by examining the

results of the JAFNPP IPA. None of the above 10 systems are dominant contributors to core

damage frequency (CDF), nor are these systems involved in the dominant initiating events.

The following is a list of the 16 Tier-2 systems:

* service water

* emergency- diesel- generator

* fuel oil

* fuel pool cooling and cleanup

* service, instrument and breathing air

* reactor building closed cooling water

" radwaste and plant drains

* security generator

" circulating water

" containment equipment drains

* main turbine generator

" sample

" turbine building closed loop cooling

" condensate

" main steam

" feedwater

2.3.1 Reactor Coolant System

LRA Section 2.3.1 states that the reactor coolant system (RCS), also called the nuclear boiler

system, includes mechanical components in the following subsystems:

* reactor vessel (includes the reactor vessel and reactor vessel internals)

* reactor water circulation

* reactor vessel instrumentation

* recirculation flow control

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* control rod drive

* neutron monitoring

The applicant .described the supporting SCs of the RCS in the following LRA sections:

" 2.3.1.1 reactor vessel

" 2.3.1.2 reactor vessel internals

" 2.3.1.3 reactor coolant pressure boundary

The staffs findings on review of LRA Sections 2.3.1.1 - 2.3.1.3 are in SER Sections 2.3.1.1 -

2.3.1.3, respectively. The staff's review of the RCS subsystems proceeded as follows.

Summary of Technical Information in the Application. LRA Section 2.3.1 describes the RCS

subsystems. Summaries of each subsystem follow.

Reactor Vessel System. The reactor vessel and internals make up the reactor vessel system.

The purpose of the reactor vessel is to contain and support the reactor core and vessel

internals and to provide a barrier to the release of radioactive materials from the core. The

reactor vessel includes the vessel shell, top and bottom heads, nozzles and penetrations,

internal and external attachments and vessel supports. The purpose of the reactor vessel

internals is to properly distribute the flow of coolant delivered to the vessel, to locate and

support the fuel assemblies, and to provide an inner volume containing the core that can be

flooded following a break in the nuclear system process barrier external to the reactor pressure

vessel. The reactor vessel internals-include the-core structureshroud support assembly,- -....

control rod guide tubes, fuel support pieces, incore flux monitor guide tubes, steam dryer, guide

rods, jet pump assemblies and jet pump instrumentation, core spray distribution lines, the

differential pressure and liquid control line, surveillance sample holders, and feedwater

spargers.

The reactor vessel system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related reactor vessel system SSCs

potentially could prevent the satisfactory accomplishment of'a safety-related function.

Reactor Water Recirculation. The purpose of the reactor water recirculation system is to provide

a variable moderator (coolant) flow to the reactor core for adjusting reactor power level.

The reactor water recirculation system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related reactor water

recirculation system SSCs potentially could prevent the satisfactory accomplishment of a

safety-related function.

Reactor Vessel Instrumentation. The purpose of reactor vessel instrumentation is to monitor

reactor vessel parameter information to ensure sufficient control of the key parameters to

facilitate safe operation of the plant. Measurements of temperature, pressure, differential

pressure, flow, level and core power are transmitted to protective systems, control systems and

to the reactor control room for operator information. Mechanical portions of the system support

the measurement of hydraulic parameters. Piping from the reactor vessel and recirculation

system passes outside primary containment to the reactor building where most sensors are

located. The reactor vessel instrumentation system also includes unused primary. containment

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piping penetrations.

The reactor vessel instrumentation has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related reactor vessel

instrumentation SSCs potentially could prevent the satisfactory accomplishment of a

safety-related function.

Recirculation Flow Control. The purpose of the recirculation flow control system is to control the

speed of the two reactor water recirculation pumps by varying the electrical frequency of the

power supply for the pumps. A variable frequency, alternating current (AC) motor-generator set

located outside the drywell supplies power to each recirculation pump motor. The pump motor

is electrically connected to the generator and is started by engaging the variable speed coupling

between the generator and its drive motor. By varying the coolant flow rate through the core,

power level may be changed. The system is arranged to allow manual control room operator

action. The rotating inertia of the motor-generator set supports a slow coastdown of flow

following some transients; however, the recirculation flow control system is not credited in any

of the design basis events.

The failure of nonsafety-related recirculation flow control system SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function.

Neutron Monitoring. The purpose of the neutron monitoring traversing incore probe (TIP)

subsystem is to provide a signal proportional to the neutron flux, at any axial location wherever

-power range detector assemblies-are located.Each TIP channel-(orsubsystem) uses a gamma

detector attached to a titanium-sheathed signal and drive cable, which is driven from outside

the primary containment by a drive mechanism. The flexible cable is contained by guide tubes

that continue into the reactor core. The guide tubes are a part of the power range detector

assembly. The TIP subsystem includes QA I primary containment isolation valve assemblies on

each guide tube entering the primary containment. These valves are closed except when the

TIP subsystem is in operation, or to support system testing or maintenance activities. Each

isolation valve assembly consists of a ball valve that closes when the TIP probe is withdrawn

and a cable shearing valve that can shear off the probe if containment isolation is required. The

valves are part of the containment boundary. Otherwise, this is an instrumentation system.

The neutron monitoring TIP system has safety-related components relied upon to remain

functional during and following DBEs.

Control Rod Drive System. The purpose of the CRD system is to provide reactivity control by

positioning the control rods to control power generation in the core. When required, the control

rod drive system is designed to insert the control rods with sufficient speed to limit fuel barrier

damage. The control rod drive system includes the control rod blades, the control rod drive

mechanisms, and the components, piping and valves of the control rod drive hydraulic system.

The CRD system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related CRD system SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function. In addition, the CRD system

performs functions that support fire protection and ATWS.

LRA Table 2.3.3-14-3 identifies the following CRD system component types within the scope of

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license renewal and subject to an AMR:

" bolting

• filter housing

" flow element

° heat exchanger (shell)

* orifice

" piping

" pump casing

o sight glass

• strainer housing

" thermowell

" tubing

• valve body

The CRD component intended function within the scope of license renewal is to provide a

pressure boundary.

2.3.1.1 Reactor Vessel

2.3.1.1.1 Summary of Technical Information in the Application

LRA Section 2.3.1.1 describes the reactor vessel, which contains the nuclear fuel core, core

support structures;- control-rods; and other parts-of the reactor core. -The major components-of

the reactor vessel include the reactor vessel shell, lower head, upper closure head, flanges,

studs, nuts, nozzles and safe ends.

LRA Table 2.3.1-1 identifies the following reactor vessel component types within the scope of

license renewal and subject to AMR:

• attachment and supports

• bolting

• nozzles and penetrations

" safe ends, thermal sleeves, caps and flanges, and shell and heads

The reactor vessel component intended functions within the scope of license renewal include:

" pressure boundary

" structural or functional support for safety-related equipment

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and the UFSAR 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

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components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.1.1.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the reactor vessel

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.2 Reactor Vessel Internals

2.3.1.2.1 Summary of Technical Information in the Application

LRA Section 2.3.1.2 describes the reactor vessel internals, which are installed inside the reactor

pressure vessel to properly distribute the flow of coolant delivered to the vessel, to locate and

support the fuel assemblies, and to provide an inner volume containing the core that can be

flooded following a break in the nuclear system process barrier external to the reactor pressure

vessel.

LRA Table 2.3.1-2 identifies the following reactor vessel internals component types within the

scope of license renewal and subject to an AMR:

" control rod guide tubes

" core spray lines

* core support

" core support rim bolts

* fuel support pieces

* incore flux monitors

* jet pump assemblies

* jet pump castings

* shroud

* shroud stabilizers

* shroud support

* steam dryers

* top guide assembly

The reactor vessel internals component intended functions within the scope of license renewal

include:

* flow distribution

* boundary of a volume in which the core can be flooded and adequately cooled in the

event of a breach in the nuclear system process barrier external to the reactor vessel

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* pressure boundary

* structural or functional support for safety-related equipment

* structural integrity so loose parts are not introduced

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and the UFSAR 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).

2.3.1.2.3 Conclusion

The staff.reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staffs

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the reactor vessel internals

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.3 Reactor Coolant Pressure Boundary

2.3.1.3.1 Summary of Technical Information in the Application

LRA Section 2.3.1.3 describes the RCPB. The following systems, in whole or in part, comprise

the RCPB:

" control rod drive

" core spray

* feedwater

* high-pressure coolant injection

• main steam

" nuclear boiler vessel instruments

" reactor core isolation cooling

" reactor water recirculation

" reactor water cleanup

" residual heat removal

" standby liquid control

LRA Table 2.3.1-3 identifies the following RCPB component types within the scope of license

renewal and subject to AMR:

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" bolting

" condensing chambers

" drive

" driver mount

• filter housing

• flow elements

* orifices

* piping and fittings less than 4 inches nominal pipe size (NPS)

• piping and fittings greater than or equal to 4 inches NPS

* pump casing and cover

* pump cover thermal barrier

* restrictors

• rupture disc

• tank (CRD accumulator)

* tank (CRD scram discharge volume)

* thermal sleeves (FW)

• thermowells less than 4 inches NPS (NBVI, RWR)

* tubing

* valve bodies less than 4 inches NPS

* valve bodies greater than or equal to 4 inches NPS

The RCPB component intended functions within the scope of license renewal include:

" flow control or spray pattern

" pressure boundary

The staff also identified that LRA Table 2.3.3-14-2 identifies the following RCS component

types within the scope of license renewal and subject to an AMR:

" bolting

" filter housing

* flow element

• heat exchanger (shell)

" orifice

" piping

" pump casing

" sight glass

* strainer housing

" tubing

" valve body

The RCS component intended function within the scope of license renewal is to provide a

pressure boundary.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and the UFSAR 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

2-39
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

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the RCPB components within

the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.2 Engineered Safety Features

LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license

renewal.

The applicant described the supporting SCs of the engineered safety features in the following

LRA sections:

* 2.3.2.1 residual heat removal

* 2.3.2.2 core spray system

* 2.3.2.3 automatic depressurization

* 2.3.2.4 high pressure coolant injection

* 2.3.2.5 reactor core isolation cooling

* 2.3.2.6 gas handling

• 2.3.2.7 primary containment penetrations

The staff s findings on review of LRA Sections 2.3.2.1 - 2.3.2.7 are in SER Sections 2.3.2.1 -

2.3.2.7, respectively.

2.3.2.1 Residual Heat Removal System

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the RHR system, which restores and maintains the coolant

inventory in the reactor vessel so that the core is adequately cooled after a loss of coolant

accident (LOCA) and cools the core during a normal shutdown. The system also cools the

containment for condensation of steam from blowdowns in design basis LOCAs. In addition, the

RHR service water system reliably supplies cooling water for RHR under post-accident and

shutdown conditions. The RHR system has the following modes of operation: (1) low-pressure

coolant injection, (2) containment spray, (3) steam condensing, (4) shutdown cooling, (5)

alternate shutdown cooling, (6) suppression pool cooling, (7) fuel pool cooling, and (8) RHR

service water to RHR cross tie.

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In low-pressure coolant injection mode, the RHR system restores and maintains the coolant

inventory in the reactor vessel after a LOCA. The containment spray mode reduces drywell

pressure following a LOCA. In the containment spray mode, the RHR pumps transfer water

from the suppression chamber through the RHR heat exchangers and heat exchanger bypass

lines, where the RHR service water removes heat. The cool water is diverted to two redundant

spray headers to lower drywell and containment pressure. The steam condensing mode may be

operated in conjunction with the RCIC system as directed by emergency operating procedures

in case of a loss of the main condenser. During reactor isolation, reactor steam may be relieved

via the relief valves to the suppression chamber where it is condensed and subcooled. Decay

heat is transferred to the RHR service water by the RHR heat exchangers used as direct steam

condensers. The shutdown cooling mode during normal shutdown and cooldown dumps steam

from the reactor vessel to the main condenser acting as a heat sink. The RHR pumps complete

reactor cooldown by pumping reactor coolant from recirculation loop B through the RHR heat

exchangers, which transfer heat to RHR service water. The cooled reactor coolant returns to

the reactor vessel via either recirculation loop. The alternate shutdown cooling mode provides a

cooling path if the normal shutdown cooling path is inoperable. The RHR pumps take suction

from the suppression pool, pass it through the RHR heat exchangers, and inject it into the

vessel via the RHR injection valves. Water overflows into the MS lines, and safety relief valves

(SRVs) open for flow to the suppression pool. The suppression pool cooling mode of RHR

takes suction from the suppression pool, passes it through the RHR heat exchangers, and

returns flow to the suppression pool. This mode of operation is designed to remove heat from

the suppression pool. The fuel pool cooling mode takes suction from the fuel pool cooling

system, passes it through the RHR heat exchangers, and discharges Lt back to the fuel pool

cooling system. This mode of operation assists in fuel pool cooling during reactor shutdown

periods as an alternate cooling system operation and is not a safety function. The emergency

reactor vessel fill mode provides a cross-tie between the RHR service water system and RHR

piping. The RHR service water pumps take suction from the service water system and inject it

into the reactor vessel through the RHR piping.

The RHR system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related RHR SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the RHR system performs

functions that support fire protection.

LRA Tables 2.3.2-1 and 2.3.3-14-4 identify the following RHR system component types within

the scope of license renewal and subject to AMR:

* bolting

* cyclone separator

* flow element

* heat exchanger (bonnet)

* heat exchanger (shell)

* heat exchanger (tubes)

* nozzle

* orifice

* piping

* pump casing

* sight glass

* steam trap

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" strainer

" strainer housing

• thermowell

• tubing

• valve body

The RHR system component intended functions within the scope of license renewal include:

* flow control

" filtration

" heat transfer

• pressure boundary

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.1 and 2.3.3.14, and UFSAR Sections 4.8.1, 4.8.3, 4.8.4,

4.8.5, and 9.7.3 using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section' 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the RHR system components

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.2 Core Spray System

2.3.2.2.1 Summary of Technical Information in the Application

LRA Section 2.3.2.2 describes the CS system, which protects the core by spraying water over

the fuel assemblies to remove decay heat following the postulated design basis LOCA. As part

of the ECCS, the CS system maintains core coolant inventory to prevent fuel damage and, in

conjunction with the primary and secondary containments, limit the release of radioactive

materials to the environs following a LOCA to keep resulting radiation exposures within

10 CFR Part 100 guideline values. The CS system consists of two redundant pumping loops,

each with a motor-driven centrifugal pump, piping, valves, spray spargers, control logic, and

instrumentation and controls. The pump suction is normally supplied from the suppression pool

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but may be lined up to the condensate storage tank (CST) after reactor shutdown. The CST

supports CS system operation for injection flow testing, for transfer of condensate to the

reactor, or for core cooling. During LOCA-initiated CS operation, the CS pumps take suction

from the suppression pool and discharge water over the top of the core. Water leaks through

the break in the RCPB into the drywell. The leaking water drains through the pressure

suppression vents back to the suppression pool, establishing a closed loop. The CS keep-full

subsystem keeps the CS system discharge piping full. The subsystem consists of a hold pump

with its associated piping, valves, instruments, and controls.

The CS system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related CS SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the CS system performs

functions that support fire protection.

LRA Tables 2.3.2-2 and 2.3.3-14-8 identify the following CS system component types within the

scope of license renewal and subject to AMR:

* bolting

* cyclone separator

" flow element

" orifice

* piping

" pump casing

" sight glass

* strainer

* tubing

• valve body

The CS system component intended functions within the scope of license renewal include:

* flow control

* filtration

* pressure boundary

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.2 and 2.3.3.14, and UFSAR Section 6.4 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).

Based on its review, the staff found that LRA Section 2.3.2.2 includes within the scope of

license renewal CS system portions that meet 10 CFR 54.4 scoping requirements. LRA

Table 2.3.2-2, "Core Spray System," also includes CS system components subject to an AMR

by 10 CFR 54.4(a) and 10 CFR 54.21(a)(1 ). The staff found no omissions.

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2.3.2.2.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the CS system components

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.3 Automatic Depressurization

2.3.2.3.1 Summary of Technical Information in the Application

LRA Section 2.3.2.3 describes the automatic depressurization system (ADS), which prevents

over-pressurization of and provides automatic depressurization for small breaks in the reactor

coolant system, allowing the low-pressure coolant injection and CS systems to inject water into

the reactor vessel. The system includes safety relief valves (SRVs), the SRV discharge lines to

the suppression pool, and the MS lines from the reactor vessel out to but not including the first

MS isolation valve. The SRVs are on the MS lines within the drywell between the reactor vessel

and the first MS isolation valves. The valves are dual-purpose in that they relieve pressure by

normal mechanical action or by automatic action of an electric-pneumatic control system. The

relief by normal mechanical action prevents over-pressurization of the reactor coolant system.

The depressurization by automatic action of the control system reduces reactor coolant system

pressure during a small-break LOCA.

The ADS has safety-related components relied upon to remain functional during and following

DBEs. In addition, the ADS performs functions that support fire protection.

LRA Table 2.3.2-3 identifies the following ADS component types within the scope of license

renewal and subject to AMR:

" bolting

" piping

* T-quencher

" valve body

The ADS component intended function within the scope of license renewal is to provide a

pressure boundary.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 4.4, 6.4.2, and 7.4.3.3 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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

2-44
components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.3 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.2.3-1 dated January 12, 2006, the staff noted that UFSAR page 498 states that each

of the 11 SRVs has a nitrogen accumulator. Such pneumatic accumulators ensure SRV ability

to depressurize the vessel in the event of a small to intermediate line break concurrent with an

HPCI failure and an interruption of the pneumatic supply to the accumulators for short-term

ADS SRV capability. Long-term operation of the SRVs is assured with the seismically-qualified

lines to the accumulators. LRA Table 2.3.2-3 does not list accumulators as within the scope of

license renewal; therefore, the staff asked the applicant to indicate whether the accumulators

had been included within the scope of license renewal and, if so, the LRA table and

subcomponent group that include the subject component or, if not, to justify the exclusion.

In its response dated February 12, 2007, the applicant stated that the accumulators are

included within the scope of license renewal as part of the service, instrument, and breathing air

system as shown on license renewal drawing FM-29A and in LRA Tables 2.3.3-10 and 3.3.2-10

as a component type of tank exposed to an internal environment of gas.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.3-1 acceptable

because of the inclusion of the component. The staffs concern described in RAI 2.3.2.3-1 is

resolved.

2.3.2.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the ADS components within

the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.2.4 High-Pressure Coolant Injection

2.3.2.4.1 Summary of Technical Information in the Application

LRA Section 2.3.2.4 describes the HPCI system, which limits the release of radioactive

materials to the environs following a LOCA to keep radiation exposures within 10 CFR Part 100

guideline values. This limited release is achieved primarily by maintaining core coolant inventory

to prevent fuel damage. The HPCI system consists of a steam turbine-driven centrifugal main

pump, a booster pump, piping, valves, controls, and instrumentation. The HPCI system is

designed to pump water into the reactor vessel over a wide range of pressures. The system

uses demineralized water supplied by a common header from the two CSTs and can also draw

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from the suppression pool, pumping water from either source into the reactor vessel via a

feedwater line. Flow is distributed within the reactor vessel through feedwater spargers. The

HPCI system turbine gland seals are vented to the HPCI system gland seal condenser and part

of the water from the HPCI system booster pump is routed through the condenser for cooling

purposes. Non-condensable gases from the gland seal condenser are vented by a gland

exhauster to the standby gas treatment system. An HPCI lube oil system supplies the main

pump, turbine (including thrust bearing), and speed reducer bearings with oil. A motor-driven

pump supplies the lube oil system when speed is too low for the shaft-driven pump. This

system contains a lube oil cooler supplied with water from the booster pump discharge.

The HPCI system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related HPCI SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the HPCI system performs

functions that support fire protection and SBO.

LRA Tables 2.3.2-4 and 2.3.3-14-14 identify the following HPCI system component types within

the scope of license renewal and subject to AMR:

" bearing housing * blower housing * bolting

" drain pot

" filter housing

" flow element

" gear box housing

" governor housing

" heat exchanger (bonnet)

• heat exchanger (shell)

" heat exchanger (tubes)

" orifice

* piping

" pump casing

* rupture disk

• sight glass

* steam trap

" strainer

" tank

" thermowell

" tubing

" turbine casing

" valve body

The HPCI system component intended functions within the scope of license renewal include:

" filtration

" flow control

" heat transfer

* pressure boundary

2.3.2.4.2 Staff Evaluation

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The staff reviewed LRA Sections 2.3.2.4 and 2.3.3.14, and UFSAR Sections 6.4 and 8.11 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).

2.3.2.4.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the HPCI system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.5 Reactor Core Isolation Cooling

2.3.2.5.1 Summary of Technical Information in the Application

LRA Section 2.3.2.5 describes the RCIC system, which cools the core during reactor isolation

by pumping makeup water into the reactor vessel when its water level is low. The RCIC system

also provides makeup water to the reactor vessel during total loss of offsite power. The RCIC

system consists of a steam-driven turbine-pump unit, valves, and piping capable of delivering

make-up water to the reactor vessel. The RCIC system normally takes suction from the

demineralized water in the CSTs with back-up supply available from the suppression pool. The

RCIC system also connects to the RHR system alignment with it when the RHR system

operates in the steam condensing mode. RCIC injection to the vessel is through the feedwater

line. The RCIC system shares suction points and full-flow test lines with the HPCI system.

The RCIC system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related RCIC SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the RCIC system performs

functions that support fire protection and SBO.

LRA Tables 2.3.2-5 and 2.3.3-14-7 identify the following RCIC system component types within

the scope of license renewal and subject to AMR:

• bolting

* filter housing

• flow meter housing

• governor housing

* heat exchanger (bonnet)

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* heat exchanger (shell)

* orifice

* piping

* pump casing

* rupture disk

* sight glass

* steam trap

* strainer

* strainer housing

* tank

* thermowell

* tubing

• turbine casing

* valve body

The RCIC system component intended functions within the scope of license renewal include:

* flow control

* filtration

• pressure boundary

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.5 and 2.3.3.14, and UFSAR Section 4.7 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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).

Based on its review, the staff found that LRA Section 2.3.2.5 includes within the scope of

license renewal RCIC portions that meet 10 CFR 54.4 scoping requirements. LRA

Table 2.3.2-5, "Reactor Core Isolation Cooling," also includes RCIC components subject to

AMRs by 10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff found no omissions.

2.3.2.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the RCIC system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.2.6 Gas Handling

2.3.2.6.1 Summary of Technical Information in the Application

LRA Section 2.3.2.6 describes the gas-handling system, which includes mechanical

components in the off-gas-holdup (OGH) and SGT subsystems. The OGH system collects,

processes, holds, and controls the gaseous radioactive waste released from the main

condenser air ejector. Discharge of this gas to the atmosphere is through the main stack, which

is also the release point for gaseous waste from the start-up mechanical vacuum pump

(condenser air removal pump) and the gland seal condenser (steam packing exhauster). The

SGT system processes gaseous effluent from the primary and secondary containments when

required to limit the discharge of radioactive materials to the environs and limit exfiltration from

the secondary containment during periods of primary containment isolation. The system

functions as part of the secondary containment system. The SGT system is designed to limit

the release of radioactive material to the environment to keep the offsite dose from a postulated

DBA within 10 CFR Part 100 or 10 CFR 50.67(b)(2) limits. During normal plant operation, the

SGT system treats potentially radioactive gases prior to discharge to the environment.

The gas-handling system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related gas-handling SSCs potentially

could prevent the satisfactory accomplishment of a safety-related function.

LRA Tables 2.3.2-6 and 2.3.3-14-1 identify the following gas handling system component types

within the scope of license renewal and subject to AMR:

" bolting

" damper housing

" duct

" fan housing

" filter

* filter unit housing

• flow element

, orifice

" piping

• sight glass

" tubing

" valve body

The gas-handling system component intended functions within the scope of license renewal

include:

" flow control

" filtration

" pressure boundary

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.6 and 2.3.3.14, and UFSAR Sections 5.3.3.4 and 11.4

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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).

Based on its review, the staff found that LRA Section 2.3.2.6 includes within the scope of

license renewal SGT system portions that meet 10 CFR 54.4 scoping requirements. LRA

Table 2.3.2-6, "Standby Gas Treatment System Components Subject to Aging Management

Review," also includes SGT system components subject to an AMR by 10 CFR 54.4(a) and

10 CFR 54.21(a)(1) The staff found no omissions.

2.3.2.6.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the gas handling system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.7 Primary Containment Penetrations

2.3.2.7.1 Summary of Technical Information in the Application

LRA Section 2.3.2.7 describes the primary containment penetrations system, which limits the

release of fission products in the event of a postulated DBA so that offsite doses do not exceed

10 CFR Part 100 guideline values. The primary containment system is of the pressure

suppression type and houses the reactor vessel, the reactor recirculating loops, and other

branch connections of the reactor coolant system. The system includes a drywell, a pressure

suppression chamber which stores a large volume of water, the connecting vent system

between the drywell and the pressure suppression pool, isolation valves, the vacuum relief

system, the RHR subsystems for containment cooling, and instrumentation and instrument

connections for periodic integrated containment leakage rate tests during reactor shutdowns.

The primary containment penetrations system has safety-related components relied upon to

remain functional during and following DBEs. The failure of nonsafety-related primary

containment penetration SSCs in the potentially could prevent the satisfactory accomplishment

of a safety-related function.

LRA Tables 2.3.2-7 and 2.3.3-14-10 identify the following primary containment penetrations

system component types within the scope of license renewal and subject to AMR:

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° bolting

* piping

" tubing

" valve body

The primary containment penetrations system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.7 and 2.3.3.14, and UFSAR Section 5.2 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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).

Based on its review, the staff found that LRA Section 2.3.2.7 includes within the scope of

license renewal primary containment penetration portions that meet 10 CFR 54.4 scoping

requirements. LRA Table 2.3.2-7, "Primary Containment Penetrations," also includes primary

containment penetration components subject to an AMR by 10 CFR 54.4(a) and

10 CFR 54.21(a)(1) The staff found no omissions.

2.3.2.7.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the primary containment

penetrations system components within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3 Auxiliary Systems

LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.

The applicant described the supporting SCs of the auxiliary systems in the following LRA

sections:

" 2.3.3.1 standby liquid control

" 2.3.3.2 service water

" 2.3.3.3 emergency diesel generator

" 2.3.3.4 fuel oil

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2.3.3.5 fire protection - water

" 2.3.3.6 fire protection - CO 2

" 2.3.3.7 heating, ventilation, and air conditioning

* 2.3.3.8 containment purge, containment atmosphere dilution, and post-accident

sampling

* 2.3.3.9 fuel pool cooling and cleanup

* 2.3.3.10 service, instrument, and breathing air

* 2.3.3.11 reactor building closed loop cooling water

* 2.3.3.12 radwaste and plant drains

* 2.3.3.13 security generator

* 2.3.3.14 miscellaneous systems in scope for (a)(2)

The staffs findings on review of LRA Sections 2.3.3.1 - 2.3.3.14 are in SER Sections 2.3.3.1 -

2.3.3.14, respectively.

2.3.3.1 Standby Liquid Control

2.3.3.1.1 Summary of Technical Information in the Application

LRA Section 2.3.3.1 describes the SLC system, a backup method to bring and maintain the

reactor subcritical from the most reactive conditions as reactor coolant cools. Maintaining

subcriticality thus ensures that the fuel barrier is not threatened by overheating in the

improbable event that not enough control rods can be inserted to counteract the positive

reactivity effects of a colder moderator. The SLC system consists of a stainless steel boron

solution tank, a test water tank, a drain tank, two positive-displacement pumps, two explosive

valves, local valves, and controls mounted in the reactor building outside the primary

containment. The liquid flows through stainless steel piping into the reactor vessel and

discharges below the core support plate where it mixes with the cooling water rising through the

core.

The SLC system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related SLC SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the SLC system performs

functions that support ATWS.

LRA Tables 2.3.3-1 and 2.3.3-14-5 identify the following SLC component types within the scope

of license renewal and subject to AMR:

" bolting

" accumulator

" orifice

* piping

* pump casing

* strainer housing

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* tank

" thermowell

" tubing

" valve body

The SLC system component intended function within the scope of license renewal is to provide

a pressure boundary.

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.1 and 2.3.3.14, and UFSAR Section 3.9 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the SLC system components

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.2 Service Water

2.3.3.2.1 Summary of Technical Information in the Application

LRA Section 2.3.3.2 describes the service water (SW) system, which provides cooling water to

safety-related and nonsafety-related plant components. The SW system is a heat sink during

normal operation for the turbine building and reactor building heat loads. Three

nonsafety-related pumps in the screenwell-pumphouse building take suction from Lake Ontario.

Two pumps normally operate and discharge through automatic self-cleaning strainers into a

common manifold. The return flow from the system enters the circulating water discharge

tunnel where it mixes with the circulating water flowing back into Lake Ontario. The emergency

SW system cools ECCS components and other equipment essential to safe reactor shutdown

following a design basis LOCA. The emergency SW system consists of two independent supply

loops, each supplied from one emergency service water pump in a separate bay in the

pumphouse, taking suction from Lake Ontario. Twin basket strainers are located at each pump

discharge. When in operation, the system discharges to the circulating water discharge tunnel

and back to Lake Ontario. The control room and relay room air handling units, normally

supplied cooling flow by a closed loop glycol system, also can be supplied by either the

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emergency or normal SW system.

The SW system water has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SW SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the service water performs

functions that support fire protection.

LRA Tables 2.3.3-2 and 2.3.3-14-30 identify the following SW system component types within

the scope of license renewal and subject to AMR:

" bolting

* flow element

" orifice

" piping

" pump casing

" strainer

" strainer housing

" tank

o thermowell

* tubing

" valve body

The SW system component intended functions within the scope of license renewal include:

* flow control

" filtration

* pressure boundary

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.2 and 2.3.3.14, and UFSAR Section 9.7 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review fo the BOP two-tier review process, 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 of LRA Sections 2.3.3.2 and 2.3.3.14 found areas in which additional

information was necessary to complete the review of the applicant's scoping and screening

results. The applicant responded to the staff's RAIs as follows.

In RAI 2.3.3.2-1 dated January 19, 2007, the staff noted that license renewal drawing

LRA-M-46A shows at locations B6, B7, and B8 four isolation valves for the drain lines and four

isolation valves on SW supply lines to the electrical bay cooling units. The license renewal

boundary for each section of piping ends at the QA-I boundary including the reducer; however,

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the isolation valves (at each supply line and at each drain line) upstream of the reducer and

piping between the reducer and isolation valves labeled as SEISMIC I are not shown as within

the scope of license renewal. The staff requested from the applicant additional information on

why these piping and isolation valves are.not within the scope of license renewal and

justification for the boundary locations as to 10 CFR 54.4(a) requirements.

In its response dated February 14, 2007, the applicant stated that the license renewal drawings

identify the SEISMIC I boundaries uniquely. The portions of the system required to maintain

pressure boundary for the system to perform its safety intended functions are identified in the

site component database as QA-I and within the system intended function boundary flags. The

SEISMIC I boundary identifies portions of the system that are seismically qualified category I

but not necessarily safety-related or QA-I. The portions of the system that were included in the

AMR, as shown by the highlighting on the license renewal drawing, include those required to

maintain the pressure boundary so functions defined in 10 CFR54.4(a)(1) or (a)(3) can be

performed.

The applicant also indicated in response to this RAI that the determination of whether a

component meets the 10 CFR 54.4(a)(2) scoping criterion is based on structural/seismic

boundary locations or the component location in a building, whether it contains gas or liquid,

and its proximity to safety-related equipment. The applicant also stated that their conservative

spaces approach to scoping in accordance with 10 CFR 54.4(a)(2) included almost all

mechanical systems within the scope of license renewal (see Table 2.3.3.14-A). System

portions beyond the QA-I boundary shown as SEISMIC I were included within the scope of

license renewal in the 10 CFR54.4(a)(2) review but are not highlighted on license renewal

drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-1 acceptable

because it confirmed inclusion of the SEISMIC I category SW piping in question within the

scope of license renewal and subject to an AMR; therefore, the staff's concern described in

RAI 2.3.3.2-1 is resolved.

In RAI 2.3.3.2-2 dated January 19, 2007, the staff noted that license renewal drawing

LRA-FM-20B shows, at location E5, SW piping 22"-WS-151-57 as within the scope of license

renewal. The line is continued on license renewal drawing LRA-FM-46A, at location B5. The

continuation on license renewal drawing LRA-FM-46A does not show the piping as within the

scope of license renewal nor include a license renewal boundary. The line is continued on a

third drawing, license renewal drawing LRA-FM-36A, not provided by the applicant. The staff

requested from applicant additional information on why this section of piping is not within the

scope of license renewal and justification for the boundary locations under 10 CFR 54.4(a).

In its response dated February 14, 2007, the applicant stated that the piping on license renewal

drawings LRA-FM-6A and LRA-FM-36A is the discharge pipe from the SW system to the

circulating water discharge. Pressure boundary integrity is not required for this portion of the

system because this piping is downstream of the cooled components. This piping is, therefore,

not subject to an AMR as part of the SW system review. As explained in LRA Section 2.1.2.1.3,

piping required for structural support or for potential spatial interaction with safety-related

equipment was included in the 10 CFR 54.4(a)(2) review but not highlighted on the license

renewal drawings,.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-2 acceptable

because it adequately described the SW piping in question continued on license renewal

drawing LRA-FM-36A previously unavailable for review. The staff accepts the applicant's

explanation that this piping is downstream from all safety-related components, is not required

for pressure integrity, and, therefore, is not within the scope of license renewal for

10 CFR 54.4(a)(1 ) or (a)(3). Therefore, the staff's concern described in RAI 2.3.3.2-2 is

resolved.

In RAI 2.3.3.2-3 dated January 19, 2007, the staff noted that license renewal drawing

LRA-M-46A shows, at location C4, SW piping 8" WCS-151-114 continued from license renewal

drawing LRA-FM-15A, location C1. Valve ESW-23 and piping upstream are labeled QA-I.

Neither of the continuation drawings (LRA-FM-1 5A and LRA-FM-36A) was submitted as part of

the LRA. The staff requested from the applicant additional information as to why this section of

QA-I piping from valve ESW-23 and upstream are not within the scope of license renewal and

justification for the boundary locations under 10 CFR 54.4(a).

In its response dated February 14, 2007, the applicant stated that valve ESW-23 and the

attached piping are the discharge of the reactor building closed loop cooling water system to

the SW discharge piping. The drawing showed these components incorrectly as QA-I. They are

no longer classified as safety-related because this flow path is not needed for that system's

intended functions. Piping required for structural support or for potential spatial interaction with

safety-related equipment was included in the 10 CFR 54.4(a)(2) review but not highlighted on

the license renewal drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-3 acceptable

because it correct the initial submission. The QA-I classification on the drawing submitted with

the LRA was in error. As this section of piping in not QA-1, the staff agrees that the piping is not

subject to an AMR for 10 CFR54.4(a)(1 ) or (a)(3); therefore, the staff's concern described in

RAI 2.3.3.2-3 is resolved.

In RAI 2.3.3.2-4 dated April 25, 2007, the staff requested from the applicant additional

information specifying what SW system portion is included within the 10 CFR 54.4(a)(2) scope

of license renewal. The information was requested because SW system SSCs are located in

many areas of the plant, and the information in the LRA was not detailed sufficiently to

determine whether any SSCs that should have been included within the scope of license

renewal per 10 CFR 54.4(a)(2) had been omitted.

In its response dated May 17, 2007, the applicant indicated that the passive mechanical

components within the 10 CFR 54(a)(2) scope of license renewal were the SW system

components located in the cable tunnel, EDG building, electric bay area, motor-generator set

room, primary containment, reactor building, gas treatment building, screenwell house, SW

pump house, and turbine building. The applicant also indicated that SW SSCs in the auxiliary

boiler building, in the turbine building below elevation 260 and on elevation 260 outside grid

coordinates 260-8D through 13G, and in the pump house in areas below elevation 255 or areas

on elevation 272 outside coordinates SW272-25A, 26A are not within the 10 CFR 54.4(a)(2)

scope of license renewal because there are no safety-related components in these buildings or

areas.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-4 acceptable

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because it clearly specified the plant areas with SW system SSCs and included within the

10 CFR 54.4(a)(2) scope of license renewal SW SSCs in all the areas of the plant with potential

spatial interaction with safety-related components. The staff's concern described in

RAI 2.3.3.2-4 is resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA, accompanying license renewal drawings, and RAI responses to

determine whether the applicant failed to identify any SSCs within the scope of license renewal.

The staff finds no such omissions. In addition, the staff's review determined whether the

applicant failed to identify any components subject to an AMR. The staff finds no such

omissions. On the basis of its review, the staff concludes that there is reasonable assurance

that the applicant has adequately identified the SW system components within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.3 Emergency Diesel Generator

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 describes the EDG system, which supplies onsite AC power adequate for

the safe shutdown of the reactor following abnormal operational transients and postulated

accidents. The EDG system includes four diesel generator units, each with an air start system

and fuel oil system. Each EDG includes several mechanical auxiliary systems that support

operation. Each engine has a closed-loop jacket water cooling system which circulates

corrosion-inhibiting coolant through the engine cylinder liners, lube oil cooler, and turbocharger

after-coolers during engine operation. Each engine is equipped with three engine-driven lube oil

gear pumps, which circulate clean, cool lubricating oil during engine operation. Each engine has

a combustion air intake system, which draws air through the air intake filter from a hooded

opening in the EDG building roof into the compressor side of the turbocharger. The exhaust

system, consisting of the turbocharger, muffler, piping, and expansion joint, removes the

combustion gases through the roof.

The EDG system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related EDG SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the EDG system performs

functions that support fire protection.

LRA Tables 2.3.3-3 and 2.3.3-14-41 identify the following EDG system component types within

the scope of license renewal and subject to AMR:

" bolting

" compressor housing

• duct

• duct flexible connection

" expansion joint

" filter housing

" heat exchanger (bonnet)

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" heat exchanger (fins)

" heat exchanger (housing)

" heat exchanger (shell)

" heat exchanger (tubes)

" heater housing

" lubricator housing

" motor housing

" muffler

" orifice

" piping

" pump casing

" sight glass

" strainer

* strainer housing

• tank

" thermowell

" tubing

" valve body

The EDG system component intended functions within the scope of license renewal include:

" flow control

" filtration

" heat transfer

" pressure boundary

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.3 and 2.3.3.14, Sections 2.2 and 3.1.51 of Entergy

Report No. JAF-RPT-05-AMM30, and UFSAR Sections 8.6.1, 8.6.2, 8.6.3, and 8.6.4 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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).

2.3.3.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the EDG system components

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.4 Fuel Oil

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 describes the fuel oil system, which stores and transfers fuel oil to the

EDG and fire protection systems. Fuel oil system components include bulk storage tanks, day

tanks, transfer pumps, piping, and valves. Each diesel generator unit has an independent fuel

oil system with a main fuel storage tank, a day tank, and pumps. Two full-capacity motor-driven

pumps fill the day tank from the storage tank. An engine-driven pump and a direct current (DC)

motor-driven pump move fuel from the day tank to the fuel injectors as two redundant engine

fuel pumping systems.

The fuel oil system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related fuel oil SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the fuel oil system

performs functions that support fire protection.

LRA Table 2.3.3-4 identifies the following fuel oil system component types within the scope of

license renewal and subject to AMR:

" bolting

" flame arrestor

flow meter housing

* injector housing

* piping

* pump casing

* strainer

* strainer housing

* tank

* tubing

• valve body

The fuel oil system component intended functions within the scope of license renewal include:

" flow control

" filtration

* pressure boundary

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 8.6 and 9.8.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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

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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

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the fuel oil system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.5 Fire Protection - Water

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 describes the fire protection-water system, which provides adequate fire

protection capability in all areas of the plant where a fire hazard may exist. The FP-water

system consists of a water supply, pumping facilities, and distribution piping and components

necessary for fire suppression. Water from Lake Ontario passes through the screenwell for a

reliable supply of fresh water for fire fighting. Electric motor and diesel engine-driven water

pumps discharge into the yard main and an underground loop encircling the entire plant that

supplies water to fixed fire suppression systems, interior hose stations, and exterior fire

hydrants. Manual fire suppression is available from exterior fire hydrants surrounding the power

block and from hose stations located inside power block areas. Fire suppression by at least one

manually-controlled hose stream is available in all areas except the primary containment. The

fixed FP systems include deluge and preaction systems with unpressurized empty pipes

controlled by a heat detection system, pressurized wet pipe systems, and pressurized dry pipe

systems with air in the pipes and automatic "closed" sprinkler heads. An air foam system with a

timed air foam discharge cycle blankets the condenser pit as well as oil floating on any water

accumulation in the pit. A manually-initiated water foam system is a backup to the HPCI pump

room water spray system. Foam pickup tubes and applicator nozzles are for manual firefighting.

The failure of nonsafety-related FP-water SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function. The FP-water system also performs functions that

support FP.

LRA Tables 2.3.3-5 and 2.3.3-14-38 identify the following FP-water system component types

within the scope of license renewal and subject to AMR:

" bolting

" expansion joint

* filter housing

* flow element

* gear box housing

* heat exchanger (bonnet)

* heat exchanger (shell)

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" heat exchanger (tube)

" heater housing

" muffler

" nozzle

" orifice

" piping

" pump casing

" sight glass

" strainer

" strainer housing

* tank

* tubing

* turbocharger housing

" valve body

The FP-water system component intended functions within the scope of license renewal

include:

" flow control

" filtration

" heat transfer

" pressure boundary

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.5 and 2.3.3.14, and UFSAR Section 9.8 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 also reviewed the safety evaluation (SE) dated August 1, 1979, approving the

applicant's Fire Protection Program and supplemental SE reports listed in Operating License

Condition 2.C(3). The applicant's FP CLB refers to this SE and summarizes the Fire Protection

Program and 10 CFR 50.48 commitments using Branch Technical Position (BTP) Auxiliary and

Power Conversion Systems Branch (APCSB) 9.5-1, "Guidelines for Fire Protection for Nuclear

Power Plants," dated May 1, 1976, and BTP APCSB 9.5-1, Appendix A, dated August 23, 1976.

The staff then reviewed those components that the applicant indicated as within the scope of

license renewal for whether the applicant had omitted any passive and long-lived components

subject to an AMR in accordance with 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.5 found areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as follows.

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In RAI 2.3.3.5-1 dated January 12, 2007, the staff stated:

LRA drawing LRA-FB-48A-0 shows the motor driven vertical turbine make up

pump (P-3), hydropneumatic tank (TK-4), and associated components as out of

scope (i.e., not colored in blue). The staff requests that the applicant verify

whether the motor driven vertical turbine make up pump, hydropneumatic tank,

and associated components are in the scope of license renewal in accordance

with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and

not subject to an AMR, the staff requests that the applicant provide justification

for the exclusion.

In its response dated February 12, 2007, the applicant stated:

The motor driven jockey fire pump (76-P-3) maintains fire system pressure

during standby operations. As shown at coordinate C-3 on drawing LRA-FB-48A,

this component is outside the quality class 'M' (augmented quality) boundary that

defines components required for 10 CFR 50.48 at JAFNPP. However, the pump

and its associated components support standby operation of the fire water

system and are being included in the scope of license renewal and subject to

aging management review. No changes are required to Table 2.3.3-5 to include

these components. Because the component types of pump casing, piping, valve

body, and sight glass exposed to raw water are already included in Table 3.3.2-5

and credit the Fire Water System Program as the aging management program, a

change to Table 3.3.2-5 for these component types is not required. For the hydro

pneumatic tank, the following aging management review results are added to

Table 3.3.2-5.

Component type Tank

Intended function Pressure boundary

Material Carbon steel

Environment Raw water

Aging Effect Requiring Management Loss of material

Aging Management Program Fire Water System

NUREG 1801 Vol. 2 Item VII.G-24 (A-33)

Table 1 Item 3.3.1-68

Notes B

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-1 acceptable

because it included the jockey pump, hydro-pneumatic tank (TK-4), and their components

within the scope of license renewal and subject to an AMR. The staff concludes that the

motor-driven jockey fire pump, hydro-pneumatic tank (TK-4), and their components are

included correctly. The staff's concern described in RAI 2.3.3.5-1 is resolved.

In RAI 2.3.3.5-2 dated January 12, 2007, the staff stated:

LRA drawing LRA-FB-48A-0 shows the yard fire hydrants to be in scope (i.e.,

colored in blue). The LRA Table 2.3.3-5, 'Fire Protection-Water System

Components Subject to Aging Management Review,' and Table 3.3.2-5, 'Fire

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Protection-Water System Summary of Aging Management Evaluation,' do not

list yard fire hydrants for the Fire Protection-Water System. According to

JAFNPP commitments to satisfy Appendix A to Branch Technical Position (BTP)

Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, 'Guidelines for

Fire Protection for Nuclear Power Plants,' May 1, 1976,' August 23, 1976

JAFNPP letter dated January 11, 1977, states that: 'the condensate storage

tanks located outdoors are protected by outside fire hydrants and associated

hose houses and equipment.' The staff requests that the applicant verify whether

the yard fire hydrants are subject to an AMR in accordance with

10 CFR 54.21(a)(1). If they are excluded from an AMR, the staff requests that

the applicant provide justification for the exclusion and address how the aging of

those hydrants will be managed for the extended period of operation to ensure

providing an effective hose stream when required. Furthermore, fire hydrants are

considered passive and long-lived components in accordance with

10 CFR 54.21.

In its response dated February 12, 2007, the applicant stated:

The yard fire hydrants are subject to aging management review as shown on

LRA-FB-49A and are included in the component type 'valve body' listed in

Table 2.3.3-5. The corresponding line item in Table 3.3.2-5 is valve body with

material gray cast iron and environment raw water (int).

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-2 acceptable

because it committed to interpret yard fire hydrants as included in the "valve body," which is

within the scope of license renewal and subject to an AMR. The staff is adequately assured that

the applicant will consider yard fire hydrants for the fire suppression appropriately during aging

management; therefore, the staff's concern described is RAI 2.3.3.5-2 is resolved.

In RAI 2.3.3.5-3, dated January 12, 2007, the staff stated:

LRA drawing LRA-FB-48A-0 shows the sprinkler heads to be in scope (i.e.,

colored in blue). The LRA Table 2.3.3-5, 'Fire Protection-Water System

Components Subject to Aging Management Review,' and Table 3.3.2-5, 'Fire

Protection-Water System Summary of Aging Management Evaluation,' do not

list sprinkler heads for the Fire Protection-Water System. The staff requests

that the applicant verify whether the sprinkler heads are subject to an AMR in

accordance with 10 CFR 54.21(a)(1). If they are excluded from an AMR, the staff

requests that the applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

Sprinkler heads are subject to aging management review as shown on

LRA-FB-49A and are included in the component type,'nozzle' listed in

Tables 2.3.3-5 and 3.3.2-5. Materials are carbon steel and copper alloy > 15%

Zn.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-3 acceptable

because it adequately explained that the sprinkler heads in question are subject to an AMR.

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Furthermore, the applicant stated that the sprinkler heads are represented in LRA

Tables 2.3.3-5 and 3.3.2-5 by the component type "nozzles." Therefore, the staff's concern

described in RAI 2.3.3.5-3 is resolved.,

In RAI 2.3.3.5-4 dated January 12, 2007, the staff stated:

LRA drawing LRA-FB-49A-0 shows the east diesel fire pump and Screenwell

Building fire suppression system and associated components as out of scope

(i.e., not colored in blue). The staff requests that the applicant verify whether the

east diesel fire pump and Screenwell Building fire suppression system and

associated components are in the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to-an AMR in accordance with 10 CFR 54.21(a)(1).

If they are excluded from the scope of license renewal and not subject to an

AMR, the staff requests that the applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

The east diesel fire pump (76-P-4) is a backup to the main diesel fire pump

(76-P-1) and electric fire pump (76-P-2) which supply all normal fire water loads.

It is not required to comply with the requirements of 10 CFR 50.48 as described

in Technical Requirements Manual (TRM) Section B 3.7.H and is therefore not in

scope for license renewal. The screenwell building fire suppression system is

shown on LRA-FB-49A at coordinates D1 to G1. This system is highlighted as

subject to aging management review with the exception of the components on

thedischarge of the east diesel fire pump which is not required for 10 CFR 50.48

compliance, and its components are included in LRA Table 3.3.2-5.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-4 acceptable. The

east diesel fire pump backs up the main diesel fire pump (76-P-1) and is not credited to meet

BTP APCSB 9.5-1, Appendix A, which requires redundant fire water pumps with independent

power supplies and controls. The applicant has redundant vertical-shaft centrifugal fire pumps

for the water supply system, one electric motor-driven and the other diesel-driven; therefore, the

staff finds that the applicant correctly excluded the east diesel fire pump from the scope of

license renewal from an AMR. The applicant included the screenwell building fire suppression

system and its components within the scope of license renewal and subject to an AMR. The

staff concludes that the screenwell building fire suppression system and its components are

included correctly. The staff's concern described in RAI 2.3.3.5-4 is resolved.

In RAI 2.3.3.5-5 dated January 12, 2007, the staff stated:

Section 4.3.1.3 of the Safety Evaluation (SE) dated August 1, 1979, states that a

30 gpm automatic electric driven centrifugal jockey pump is located in the same

room as the electric motor driven fire pump. The jockey pump takes suction from

the intake sump to maintain about 150 psig in the fire water system yard loop.

The jockey pump and its associated components appear to have fire protection

intended functions required for compliance with 10 CFR 50.48 as stated in

10 CFR 54.4. The staff requests that the applicant verify whether the jockey

pump and its associated components are in the scope of license renewal in

accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

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10 CFR 54.21(a)(1). If they are excluded from: the scope of license renewal and

not subject to an AMR, the staff requests that the applicant provide justification

for the exclusion.

In its response dated February 12, 2007, the applicant stated:

The motor driven jockey fire pump (76-P-3) maintains fire system pressure

during standby operations. As shown at coordinate C-3 on drawing LRA-FB-48A,

this component is outside the quality class 'M' (augmented quality) boundary that

defines components required for 10 CFR 50.48 at JAFNPP. However, the pump

and its associated components support standby operation of the fire water

system and are being included in the scope of license renewal and subject to

aging management review. Because the component types of pump casing,

piping, valve body, and sight glass exposed to raw water are already included in

Tables 2.3.3-5 and 3.3.2-5 and credit the Fire Water System Program as the

aging management program, a change to the LRA tables for these component

types is not required.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-5 acceptable

because it included the motor-driven jockey fire pump (76-P-3) and its components within the

scope of license renewal and subject to an AMR. The staff concludes that the motor-driven

jockey fire pump and its components are included correctly. The staff's concern described in

RAI 2.3.3.5-5 is resolved.

In RAI 2.3.3.5-6 dated January 12, 2007, the staff stated:

Section 4.3.1.4 of the SE dated August 1, 1979, discusses interior hose stations

in plant areas. The staff requests that the applicant to verify whether these

interior hose stations and their associated components are in the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in

accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of

license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

The interior hose stations have intended functions that are required for

10 CFR 54.4(a)(3) and are therefore included in the scope of license renewal.

These hose stations are included in the structural aging management review in

the 'Fire hose reels' line item in LRA Tables 2.4-4 and 3.5.2-4, for bulk

commodities. Piping and valve components supplying raw water to the hose

reels are included in Tables 2.3.3-5 and 3.3.2-5 and credit the Fire Water

System Program as the aging management program. As stated in LRA

Section B.1.13.2, the fire hoses on these hose reels are periodically replaced

and are therefore not subject to aging management review. This is consistent

with NUREG-1800, Table 2.1-3 which classifies fire hoses as consumables.

Based on its review, the staff finds the applicant'sresponse to RAI 2.3.3.5-6 acceptable

because it adequately explained that the interior hose stations in question are within the scope

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of license renewal and subject to an AMR. The applicant stated that LRA Tables 2.4-4 and

3.5.2-4 includes the hose stations in the structural AMR.in the "Fire hose reels" line item for bulk

commodities. LRA Tables 2.3.3-5 and 3.3.2-5 include piping and valve components supplying

raw water to the hose reels. The staff's assurance that the applicant will consider the interior

hose stations and their components for firefighting appropriately during plant aging

management is adequate; therefore, the staff's concern described in RAI 2.3.3.5-6 is resolved.

In RAI 2.3.3.5-7 dated January 12, 2007, the staff stated:

Section 4.3.1.5 of the SE dated August 1, 1979, discusses preaction sprinkler

systems provided in the recirculation pumps motor generator set room and in the

emergency diesel generator rooms. The LRA does not list preaction sprinkler

systems and their associated components provided in the recirculation pumps

motor generator set room and in the emergency diesel generator rooms as being

in scope and subject to an AMR. The staff requests that the applicant verify

whether the preaction sprinkler systems and their associated components are in

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

an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the

scope of license renewal and not subject to an AMR, the staff requests that the

applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

Pre-action sprinkler systems and associated components in the recirculation

pumps motor generator set room (LRA-FB-49A, coordinate G-6) and emergency

diesel generator rooms (LRA-FB-49A, coordinate F-2) are subject to aging

management review with components included in LRA Tables 2.3.3-5 and

3.3.2-5 and highlighted on referenced LRA drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-7 acceptable

because it committed to include pre-action sprinkler systems and their components installed in

the recirculation pumps motor generator set and EDG rooms within the scope of license

renewal and subject to an AMR. Therefore, the staff's assurance that the applicant will consider

the fire water systems for fire suppression in the recirculation pumps motor generator set and

EDG rooms appropriately during aging management is adequate and the staffs concern

described in RAI 2.3.3.5-7 is resolved.

In RAI 2.3.3.5-8 dated January 12, 2007, the staff stated:

Section 4.3.1.5 of the SE dated August 1, 1979, discusses manual water spray

systems in the HPCI pump room and reactor core isolation coolant (RCIC) pump

room; in the vicinity of the standby gas treatment (SGT) system charcoal filters,

hydrogen seal oil unit, and turbine generator bearing boxes; and in the reactor

feed-pump turbine area and piping area. The LRA does not list manual water

spray systems provided in HPCI and RCIC pump rooms; in the vicinity of the

SGT system charcoal filters, hydrogen seal oil unit, and turbine generator

bearing boxes; and in the reactor feed-pump turbine area and piping area as

being in scope and subject to an AMR. The staff requests that the applicant

verify whether the manual water spray systems and their associated components

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

subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded

from the scope of license renewal and not subject to an AMR, the staff requests

that the applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

Water spray systems in the HPCI pump rooms (LRA-FB-49A, coordinate F-7),

RCIC pump rooms (LRA-FB-49A, coordinate F-7), SGT system charcoal filters

(LRA-FM-49A, coordinates F-7), hydrogen seal oil unit (LRA-FB-49A, coordinate

E-3), turbine generator bearing boxes (LRA-FB-49A, coordinate G-5), and

reactor feed pump turbine and piping area (LRA-FB-49A, coordinates D-3, F-3)

are subject to aging management review with components included in LRA

Tables 2.3.3-5 and 3.3.2-5 and highlighted on referenced LRA drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-8 acceptable

because it indicated the water spray systems in the HPCI and RCIC pump rooms, SGT system

charcoal, turbine generator bearing boxes, and reactor feed pump turbine and piping area

highlighted on the license renewal drawings. Therefore, the staff's assurance that the applicant

will consider the water spray systems for fire suppression of the HPCI and RCIC pump rooms,

SGT system charcoal, turbine generator bearing boxes, and reactor feed pump turbine and

piping area appropriately during aging management is adequate and the staff's concern

described in RAI 2.3.3.5-8 is resolved.

In RAI 2.3.3.5-9 dated January 12, 2007, the staff stated:

Section 4.5 of the SE dated August 1, 1979, discusses flood drains provided in

all plant areas protected with fixed water fire suppression system. The

curbs/dikes are provided for liquid tanks in the diesel fire pump area, the dirty oil

storage rooms, and main oil sump room to contain oil and fire water. The LRA

does not list flood drains and curbs/dikes as being in scope and subject to an

AMR. The staff requests that the applicant verify whether the flood drains and

curbs/dikes are in the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1).

If they are excluded from the scope of license renewal and not subject to an

AMR, the staff requests that the applicant provide justification for the exclusion.

In its response dated February 12, 2007, the applicant stated:

Drain system components provided for protection of equipment from fire

suppression water are in scope and subject to aging management review. They

are part of the radwaste and plant drains system described in Section 2.3.3.12 of

the LRA. The components subject to aging management review in this system

are described in LRA Tables 2.3.3-12 and 3.3.2-12. "Flood curbs" are structural

commodities that are in scope and subject to aging management review and

included in LRA Tables 2.4-4 and 3.5.2-4, for bulk commodities.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-9 acceptable.

Although the SE addresses these floor drains as parts of the fire suppression system, they are

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not included in LRA Section 2.3.3.5, "Fire Protection-Water," LRA Table 2.3.3.5, "Fire

Protection-Water System," or LRA Table 3.3.2-5, "Fire Protection-Water System Summary of

Aging Management Evaluation." Instead, they are included in LRA Section 2.3.3.12, "Radwaste

and Plant Drains," LRA Table 2.3.3-12 "Radwaste and Plant Drains Systems," and LRA

Table 3.3.2-12, "Radwaste and Plant Drains Summary of Aging Management Evaluation," as

within the scope of license renewal and subject to an AMR. Flood drains are listed as flood

curbs in the structural commodities and are within the scope of license renewal and subject to

an AMR. The flood drains are included in LRA Tables 2.4-4 and 3.5.2-4 for bulk commodities.

Because the applicant has committed to interpret these floor drains as included in the

radioactive waste system within the scope of license renewal and subject to an AMR, the staff's

assurance that the applicant will consider floor drains for fire suppression appropriately during

plant aging management is adequate. Therefore, the staff's concern described in RAI 2.3.3.5-9

is resolved.

In RAI 2.3.3.5-10 dated January 12, 2007, the staff stated:

Section 4.11 of the SE dated August 1, 1979, discusses the installation of fire

resistance coating on exposed structural steel in the plant areas where the

failure of exposed structural steel supporting fire barriers (floors, walls, and

ceilings) could impair the safe-shutdown capability of the plant. These areas

include the reactor building, turbine building, control building, diesel generator

building, and others. The LRA does not list three-hour rated fire resistance

coating for exposed structural steel as being in scope and subject to an AMR.

The staff requests that the applicant verify whether the fire resistance coating for

structural steel is in 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 structural fire

resistance coating is excluded from the scope of license renewal and not subject

to an AMR, the staff requests that the applicant provide justification for the

exclusion.

In its response dated February 12, 2007, the applicant stated:

Flame retardant coatings are in scope and subject to aging management review

and are included in the line item "Fire proofing" in LRA Tables 2.4-4 and 3.5.2-4,

for bulk commodities..

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-10 acceptable

because LRA Tables 2.4-4 and 3.5.2-4 list flame retardant coatings as fire proofing in the line

item in under bulk commodities as within the scope of license renewal and subject to an AMR.

Therefore, the staff's assurance that the applicant will consider structural steel flame retardant

coatings for FP appropriately during aging management is adequate. Therefore, the staff's

concern described in RAI 2.3.3.5-10 is resolved.

In RAI 2.3.3.5-11 dated January 12, 2007, the staff stated that the applicant is required to meet

BTP APCSB 9.5-1, Appendix A. According to the applicant's commitments, its letter dated

January 11, 1977, states that:

The Emergency Diesel Generator A and C combined ventilation air intake is

located approximately 40 ft from the Station Reserve Transformer, T-3. This air

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intake is approximately 10 ft above the ground. It is not practicable to seal this

opening with a 3 hr fire barrier or by a combination of opening seals and water

spray.

The Power Authority does not consider it necessary to provide a 3 hr fire barrier

between the ventilation opening and the transformer for the following reasons:

1) The transformer is protected by an automatic water spray deluge system in

accordance with NFPA 13.

The staff asked the applicant to verify whether the automatic water deluge system for Station

Reserve Transformer T-3 is within the 10 CFR 54.4(a) scope of license renewal and subject to

an AMR by 10 CFR 54.21(a)(1). If excluded from the scope of license renewal and not subject

to an AMR, the staff asked the applicant to justify the automatic water deluge system's

exclusion.

In its response dated February 12, 2007, the applicant stated, as shown on license renewal

drawing LRA-FB-49A at location E-3, the automatic water deluge system protecting Station

Reserve Transformer T-3 is within the scope of license renewal, subject to an AMR, and

included in LRA Tables 2.3.3.5 and 3.3.2-5.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-11 acceptable

because it included the automatic water deluge system and its components protecting its

station reserve transformer within the scope of license renewal and subject to an AMR.

Therefore, the staff's concern described in RAI 2.3.3.5-11 is resolved.

2.3.3.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the FP-water system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.6 Fire Protection - C02

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 describes the FP-C0 2 system, which provides FP in areas where use of a

water spray or a sprinkler system is not feasible. There are fixed total flooding carbon dioxide

(C0 2) suppression systems for the cable spreading room, cable run rooms, relay room, each of

the two electrical bay switchgear rooms, and each of the two emergency diesel-generator

switchgear rooms. Liquid C02 is stored in two refrigerated low-pressure tanks. A three-ton

low-pressure storage tank supplies the systems in the EDG switchgear rooms and a nearby

C02 system hose reel station in the turbine building. A ten-ton low-pressure storage tank

supplies the remaining systems and two hose stations and also provides C02 to purge the main

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generator hydrogen system.

The FP-C0 2 system performs functions that support FP.

LRA Tables 2.3.3-6 and 2.3.3-14-38 identify the following FP-C0 2 system component types

within the scope of license renewal and subject to an AMR:

0 bolting

• coil

0 nozzle

0 piping

* tank

" tubing

" valve body

The FP-C0 2 system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and UFSAR Section 9.8 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 also reviewed the SE dated August 1, 1979, approving the applicant's Fire Protection

Program and supplemental SE reports listed in Operating License Condition 2.C(3). The FP

CLB refers to this SE and summarizes the Fire Protection Program and 10 CFR 50.48

commitments using BTP APCSB 9.5-1 and BTP APCSB 9.5-1, Appendix A guidance. The staff

then reviewed those components that the applicant included within the scope of license renewal

to verify that the applicant did not omit any passive and long-lived components subject to an

AMR in accordance with 10 CFR 54.21(a)(1).

The staffs review of LRA Section2.3.3.6 found areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as follows.

In RAI 2.3.3.6-1 dated January 12, 2007, the staff stated that LRA Section 2.3.3.6 describes the

CO2 fire suppression system as within the scope of the license renewal and subject to an AMR.

The AMP for the CO2 fire suppression system does not appear in LRA Section B.1.13, "Fire

Protection Program." GALL AMP XI.M26, "Fire Protection," which describes C02 fire

suppression system aging management, requires that an AMP to evaluate the periodic visual

inspection and function test at least every six months for signs of system degradation. Material

conditions that may affect system performance (e.g., corrosion, mechanical damage, or

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damage to dampers) are observed during these tests. The staff asked the applicant to describe

in LRA Section B.1.13 the AMP and operating experience for the CO2 fire suppression system.

In its response dated February 12, 2007, the applicant stated that, although LRA Table 3.3.2-6

credits the Fire Protection Program for the management of C02 fire suppression system

component aging effects, the system was omitted inadvertently from the description of the Fire

Protection Program. The applicant revised the LRA Section B.1.13.1 program description to

include the following sentence:

The Fire Protection Program also includes management of the aging effects on

the intended function of the C02 fire suppression system.

The applicant also added to LRA Section B.1.13.1 the following exception to the GALL Report:

Attributes Affected Exception

3. Parameters The functional test of the CO2 fire suppression system is

Monitored/Inspected performed on a 24-month basis as listed in the current

licensing basis for JAF. This frequency is sufficient to ensure

4. Detection of Aging Effects system availability and operability based on station operating

history and to ensure that aging effects will be properly

managed through the period of extended operation.

The staff accepted the position that, in the absence of age-related degradation adversely

affecting system operation and provided that visual inspections of component external surfaces

are performed every six months, the periodicity specified in the CLB for functional testing of the

C02 system is sufficient to ensure system availability and operability.

LRA Section B. 1.13 already describes C02 fire suppression system operating experience in the

following statements:

QA audits and surveillances in 2002 and 2003 revealed that the material

condition of system equipment was good and met licensing requirements. The

audits and surveillances revealed no issues or findings that could impact

effectiveness of the program to manage aging effects for fire protection

components.

In March 2005, NRC completed a triennial fire protection team inspection to

assess whether the plant has implemented an adequate fire protection program

and that post-fire safe shutdown capabilities have been established and are

being properly maintained. Results confirmed that plant personnel were

maintaining the fire protection systems in accordance with their fire protection

program and identifying program deficiencies and implementing appropriate

corrective actions.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-1 acceptable

because it states that LRA Section B.1.13.1 omitted the C02 fire suppression system AMP

inadvertently from the description of the Fire Protection Program. The applicant revised LRA

Section B.1.13.1 to include the C02 fire suppression system AMP. LRA Table 3.3.2-6 includes

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the C02 fire suppression system component AMR. The staff's assurance that the applicant will

consider the C02 fire suppression system and its components appropriately during plant aging

management is adequate. Therefore, the staff's concern described in RAI 2.3.3.6-1 is resolved.

In RAI 2.3.3.6-2 dated January 12, 2007, the staff stated that LRA Tables 2.3.3-6 and 3.3.2-6

exclude several types of C02 fire suppression system components that appear in license

renewal drawing LRA-FB-56A-0 colored purple:

* strainer

" strainer housing

" filter housing

" heater housing

* orifice

* siren body

" pipe supports

" couplings

" odorizer

" threaded connections

* pneumatic actuators

The staff asked the applicant to determine for each whether the component should be included

in LRA Tables 2.3.3-6 and 3.3.2.6, and, if not, to justify the exclusion.

In its response dated February 12, 2007, the applicant stated that the pneumatic actuators are

active components and therefore not subject to an AMR. Pipe supports are subject to an AMR

and included in LRA Table 2.4-4 with AMR results in LRA Table 3.5.2-4 under "Component and

piping supports."

There are no strainer, strainer housing, filter housing, heater housing, siren body, or odorizer

component types in the FP-C0 2 system, nor are they shown on license renewal drawing

LRA-FB-56A-0. Orifice, coupling, and threaded connection component types which contain C02

are subject to an AMR and included in the component type "Piping" in LRA Tables 2.3.3-6

and 3.3.2.6.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-2 acceptable.

Although the applicant states that it considers these components included in other line items,

the LRA line item descriptions do not actually list all these components specifically. The

applicant properly included the following components with the other line items within the scope

of license renewal and subject to an AMR: pipe supports, orifice, coupling, and threaded

connection. The staff's assurance that the applicant will consider these components

appropriately during plant aging management is adequate. The staff finds that the LRA did not

include pneumatic actuators in the line item descriptions. The staff recognizes that the

applicant's interpretation of this component as active (short-lived component) will result in more

vigorous oversight of its condition and performance. Because the applicant has interpreted

pneumatic actuators as active, which is not within the scope of 10 CFR 50.54, the staff

concludes that their exclusion from the scope of license renewal is correct and that they are not

subject to an AMR. The staff finds that the following components in questions are not parts of

the CO2 system: strainer, strainer housing, filter housing, heater housing, siren body, or

odorizer; therefore, the staff's concern described in RAI 2.3.3.6-2 is resolved.

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In RAI 2.3.3.6-3 dated January 12, 2007, the staff stated that, according to the applicant's

commitments to satisfy BTP APCSB 9.5-1, Appendix A, its letter dated January 11, 1977, states

that

... the plant computer room is located within a wire fence area inside the relay

room... The relay room (including computer room) is protected by a total flooding

C02 system with outside backup by a water hose station and portable C02

extinguisher.

UFSAR Section 9.8.3.11 states that, "Halon is used for fire protection in the Emergency and

Plant Information Computer (EPIC) Room where it is not desirable to use a water spray or a

sprinkler system." The staff asked the applicant to verify whether the flooding C02 fire

suppression system or Halon fire suppression system in the EPIC room is within the

10 CFR 54.4(a) scope of license renewal and subject to an AMR by 10 CFR 54.21(a)(1). If the

C02 or Halon fire suppression system is excluded from the scope of license renewal and not

subject to an AMR, the staff requested justification for the exclusion.

In its response dated February 12, 2007, the applicant stated that the EPIC system is neither

safety-related nor credited to support a safe-shutdown in any fire scenarios to demonstrate

compliance with 10 CFR 50.48 and that, therefore, the Halon system in the EPIC room is not

required to support 10 CFR 50.48 and not within the scope of license renewal nor subject to an

AMR.

As stated in LRA Section 2.3.3.6 and shown in LRA Table 2.3.3-6, the total flooding C02 fire

suppression system for the relay room is within the scope of license renewal. LRA Table 3.3.2-6

lists and license renewal drawing LRA-FB-56A shows AMR results for components in this

system portion.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-3 acceptable. The

staff finds that the EPIC system is not safety-related, cannot affect safety-related equipment by

spatial interaction, is not required for safe-shutdown, and, therefore, has no 10 CFR 54.4(a)(2)

intended function and that the applicant correctly excluded the Halon system in the EPIC room

from the scope of license renewal and from any AMR. The total flooding C02 fire suppression

system for the relay room is within the scope of license renewal and subject to an AMR. LRA

Table 3.3.2-6 lists and license renewal drawing LRA-FB-56A shows AMR results for the

components in this system portion. Therefore, the staff's concern described in RAI 2.3.3.6-3 is

resolved.

2.3.3.6.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staffs

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the fire protection-CO 2

system components within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.7 Heating, Ventilation, and Air Conditioning

2.3.3.7.1 Summary of Technical Information in the Application

LRA Section 2.3.3.7 describes the heating, ventilation, and air conditioning (HVAC) system,

which controls the station air temperatures and the flow of airborne radioactive contaminants to

ensure the operability of station equipment and the accessibility and habitability of station

buildings and compartments. The HVAC systems include numerous systems which together

comprise plant HVAC equipment, including:

" reactor building ventilation

" turbine building ventilation

* drywell ventilation and cooling

" radwaste building ventilation

• control room and relay room ventilation and cooling

" administration building ventilation and cooling

" screenwell and water treatment ventilation system

* EDG building HVAC

° ventilation radiation monitoring subsystem of process radiation monitor system " security building ventilation

The reactor building ventilation system controls ambient temperatures, humidity, and the flow of

potentially airborne radioactive contaminants for operability of equipment and accessibility and

habitability of plant buildings and compartments. The turbine building ventilation system

controls plant ambient temperature, humidity, and the flow of potentially airborne radioactive

contaminants. The turbine building ventilation system supplies filtered and tempered outdoor air

to the operating floor and all other areas below the operating floor. The drywell ventilation and

cooling system circulates cooled nitrogen around the drywell, including areas around the

reactor recirculation pumps and motors, the control rod drive area, and the annular space

between the reactor vessel and the primary shield. The radwaste building ventilation system

removes heat rejected from operating equipment compartments to maintain required space

temperatures. The control and relay rooms ventilation and cooling system provides adequate

ventilation, heating, cooling, and relative humidity for those rooms. The control and relay room

air conditioning systems operate independently of other plant HVAC services. These systems

must operate at all times during normal, shutdown, and DBA conditions. The administration

building ventilation and cooling system provides adequate ventilation, heating, cooling, and

relative humidityfor areas within the administration building. This system includes the

administration building ventilation and cooling, administration and support building ventilation

and cooling, warehouse building ventilation and cooling, station battery room ventilation and

cooling, SW for admin building cooling, and technical support center/EPIC room ventilation. The

screenwell and water treatment ventilation system provides ventilation and heating within the

screenwell / water treatment building. The EDG building HVAC conditioning system heats and

ventilates the EDG rooms and EDG sWitchgear rooms. The process radiation monitor system,

which monitors process liquid and gas lines that may serve as discharge routes for radioactive

materials, consists of a number of radiation monitors and monitoring subsystems with automatic

actions and control room indications. The security access building houses a propane-powered

generator for backup power to selected security loads and yard lighting. For engine cooling, the

building is equipped with air intake louvers and discharge ducts with air movement produced by

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the engine fan.

The HVAC system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related HVAC SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the HVAC system

performs functions that support fire protection.

LRA Tables 2.3.3-7, 2.3.3-14-11, 2.3.3-14-32, 2.3.3-14-33, 2.3.3-14-34, 2.3.3-14-35, and

2.3.3-14-36 identify the following HVAC system component types within the scope of license

renewal and subject to AMR:

" bolting

" compressor housing

" damper housing

" duct

* duct flexible connection

" fan housing

" filter housing

" flow element

• heat exchanger (bonnet)

" heat exchanger (fins)

" heat exchanger (housing)

" heat exchanger (shell)

" heat exchanger (tubes)

" heat exchanger (tubesheet)

*. louver housing

* orifice

* piping

* pump casing

* sight glass

* strainer

• strainer housing

" tank

• tubing

" valve body

The HVAC system component intended functions within the scope of license renewal include:

" flow control

" filtration

" heat transfer

* pressure boundary

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.7 and 2.3.3.14, and UFSAR Sections 9.9.3.3, 9.9.3.4,

5.2.3.7, 9.9.3.5, 9.9.3.11, 9.9.3.6, 9.9.3.10, 9.9.3.7, 9.9.3.9, and 7.12 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

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During its review, the staff evaluated the system functions described in the LRA and 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).

2.3.3.7.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the HVAC system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.8 Containment Purge, Containment Atmosphere Dilution, and Post-Accident

Sampling

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 describes the containment purge (CP), containment atmosphere dilution

(CAD), and post-accident sampling system (PASS), which includes the primary containment

atmosphere control and dilution system, drywell purge ventilation supply and exhaust systems,

venting and vacuum relief system, and PASS. The system establishes and maintains the

desired atmosphere in the primary containment, provides the means to control the relative

oxygen concentration by inerting the containment atmosphere with nitrogen or deinerting it with

outside air, monitors containment hydrogen and oxygen concentrations, and controls primary

containment pressure and differential pressure via makeup to or venting from the drywell and

suppression chamber. The system also provides nitrogen to pneumatically-operated I&C in the

containment and a meas to collect and analyze liquid and gaseous samples from containment

following a LOCA.

The containment atmosphere is monitored via redundant dual-range hydrogen and oxygen

analyzers sampling at four separate locations, three in the drywell and one in the torus. The

sample lines are redundant to each analyzer. The primary containment is deinerted by fresh

outside air from a vent and purge supply fan. During both inerting and deinerting processes, the

SGT system processes gas purged from the torus and drywell before exhausting it to the

atmosphere. Nitrogen makeup maintains drywell pressure, drywell-to-torus differential pressure,

and primary containment oxygen concentration within required limits. Instrumentation and

pneumatically-operated valves in the primary containment are supplied with nitrogen gas

instead of air to prevent a buildup of oxygen in the containment. Containment isolation valves

outside the primary containment for the RBCLC water system also are supplied with nitrogen.

The PASS obtains representative liquid and gaseous samples from within the primary

containment and gaseous samples from within the secondary containment for radio-chemical

and chemical analyses in a LOCA. From interpretation of this data, the extent of core damage

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and other radiological and chemical conditions in the plant can be predicted. The basic system

consists of a liquid and gas sample station in the reactor water recirculation pump motor

generator set room outside the secondary containment structure. The system is also designed

to provide useful samples under conditions ranging from normal shutdown and power operation

to design-basis LOCA.

The CP, CAD, and PASS has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related CP, CAD, and PASS SSCs

potentially could prevent the satisfactory accomplishment of a safety-related function. In

addition, the CP, CAD, and PASS performs functions that support FP.

LRA Tables 2.3.3-8 and 2.3.3-14-15 identify the following CP, CAD and PASS component types

within the scope of license renewal and subject to AMR:

• bolting

* filter housing

" flow element

" heat exchanger (coil)

" heat exchanger (tubes)

" heater housing

" orifice

" piping

* pump casing

• sample trap

" tank

• tubing

* valve body

The CP, CAD, and PASS component intended functions within the scope of license renewal

include:

" heat transfer

• pressure boundary

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.8 and 2.3.3.14, and UFSAR Sections 5.2.3.6, 5.2.3.7,

5.2.3.8, 5.2.3.14, and 9.14.4 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).

On the basis of its review the staff found that LRA Section 2.3.3.8 includes CP, CAD and PASS

portions that meet 10 CFR 54.4 scoping requirements within the scope of license renewal. LRA

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Table 2.3.3-8 also include CP, CAD and PASS components subject to an AMR by

10 CFR 54.4(a) and 10 CFR Part 54.21(a)(1). The staff found no omissions.

2.3.3.8.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the containment purge,

containment atmosphere dilution, and post-accident sampling system components within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.9 Fuel Pool Cooling and Cleanup

2.3.3.9.1 Summary of Technical Information in the Application

LRA Section 2.3.3.9 describes the fuel pool cooling and cleanup (FPCC) system, which

provides a criticality safe underwater storage location for spent fuel assemblies requiring

shielding and cooling during storage and handling. The construction and configuration of the

spent fuel racks preclude the possibility of criticality under normal and abnormal conditions. The

spent fuel pool, fuel pool gates, and connected cooling system piping are arranged for a

minimum level over fuel seated in the pool to shield plant personnel adequately. The FPCC

system controls spent fuel storage pool temperature, maintains spent fuel storage pool water

clarity, and minimizes the concentration of fission and corrosion products in the spent fuel

storage pool. The FPCC system cools and purifies the spent fuel storage pool by passing the

pool water through two heat exchangers, transferring heat to the reactor building closed loop

cooling water system. Water purity and clarity in the spent fuel storage pool, reactor head

cavity, and reactor internals storage pit are maintained by filtering and demineralizing. There is

additional capability to add water to the pool through a cross-tie to the RHR system when

normal makeup system is lost and pool water level is threatened due to heavy pool water

inventory loss.

The FPCC system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related FPCC SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

LRA Tables 2.3.3-9 and 2.3.3-14-12 identify the following FPCC system component types within

the scope of license renewal and subject to AMR:

" bolting

" diffuser

" flow element

" heat exchanger (shell)

" neutron absorber

" orifice

* piping

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" pump casing

" tank

" thermowell

" tubing

* valve body

The FPCC system component intended functions within the scope of license renewal include:

* flow control

• neutron absorption

• pressure boundary

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.9 and 2.3.3.14, Sections 2.2 and 3.1.14 of Entergy

Report No. JAF-RPT-05,-AMM30, and UFSAR Sections 9.3 and 9.4 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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 of LRA Sections 2.3.3.9 and 2.3.3.14 found an area in which additional

information was necessary to complete the review of the applicant's scoping and screening

results. The applicant responded to the staff's RAI as follows.

In RAI 2.3.3.9-1 dated January 19, 2007, the staff noted that license renewal drawing

LRA-FM-19A, at locations F3 and F4, shows lines W19-151-1A, 1B, and 17 from skimmer

surge tanks TK-8A and TK-8B to surge tank drain valve VGW-15A as not within the scope of

license renewal. The piping and components upstream from VGW-15A are labeled SEISMIC I.

The staff requested additional information as to why these pipe and component sections are not

within the 10 CFR 54.4(a) scope of license renewal and justification for the boundary locations.

In its response dated February 14, 2007, the applicant stated:

The seismic I boundaries are uniquely identified on the license renewal

drawings. The portions of the system required to maintain pressure boundary for

the system to perform its safety functions are identified in the site component

database as QA category I and identified within the system intended function

boundary flags. The seismic I boundary identifies those portions of systems that

are seismically qualified category I but not necessarily safety-related or QAI.

The portions of the system that Were included in the aging management review

as shown by the highlighting on the LRA drawing include the portions of the

system required to maintain the pressure boundary and ensure that functions

defined in 10CFR54.4(a)(1) or (a)(3) can be performed.

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The portions of the system beyond the QA I boundary that are identified as

Seismic I were included in scope as part of the 10 CFR 54.4(a)(2) review, but are

not highlighted on individual LRA drawings, as described in LRA

Section 2.1.2.1.3.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-1 acceptable

because it adequately justified omission of the piping sections in question from the scope of

license renewal under 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3). The staff agrees that integrity

of these piping sections is not required to maintain the pressure boundary. The applicant further

explained that system portions beyond the QA I boundary shown as SEISMIC I were included

within the scope of license renewal in the 10 CFR 54.4(a)(2) review. Therefore, the staff's

concern described in RAI 2.3.3.9-1 is resolved.

2.3.3.9.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the FPCC system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.10 Service, Instrument, and Breathing Air

2.3.3.10.1 Summary of Technical Information in the Application

LRA Section 2.3.3.10 describes the service, instrument, and breathing air system, which

provides a continuous supply of oil-free compressed air directed to plant breathing air,

instrumentation, and general plant services. The compressed air to the breathing, instrument,

and service air subsystems is supplied by three air compressors arranged in parallel to

discharge air through individual air receivers with a common discharge header feeding three

instrument air dryers. This common discharge header also supplies air to the breathing air

headers and the instrument air headers after passing through two air dryers installed in parallel.

Each of the dryers has pre-filters and after-filters to ensure that no particulate matter enters the

system. The breathing air system has a breathing air accumulator. Instrument air is available as

a backup to drywell instrumentation and controls, which are normally supplied with nitrogen via

the instrument air line. Nitrogen is used so any leakage will not dilute the nitrogen-inerted

primary containment. The normal source of nitrogen is the primary containment atmosphere

control and dilution system.

The service, instrument, and breathing air system has safety-related components relied upon to

remain functional during and following DBEs. The failure of nonsafety-related service,

instrument, and breathing air SSCs potentially could prevent the satisfactory accomplishment of

a safety-related function.

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LRA Tables 2.3.3-10 and 2.3.3-14-25 identify the following service, instrument, and breathing

air system component types within the scope of license renewal and subject to AMR:

" bolting

* piping

" quick connect

" tank

* tubing

* valve body

The service, instrument, and breathing air system component intended function within the

scope of license renewal is to provide a pressure boundary.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.10 and 2.3.3.14, Sections 2.2 and 3.1.28 of Entergy

Report No. JAF-RPT-05-AMM30, and UFSAR Section 9.11 using the evaluation methodology

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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 of LRA Sections 2.3.3.10 and 2.3.3.14 found 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 staffs RAIs as follows.

In RAI 2.3.3.10-1 dated January 19, 2007, the staff noted that license renewal

drawing LRA-M-29A-0, at location G7, shows that the in-scope nitrogen supply for RCPB air

operated valves (AOVs) 02AOV-17 and 02AOV-18 does not extend to the actuator but

terminates at the downstream side of solenoid valves (SOVs) SOV-1 7 and SOV-1 8,

respectively. The staff requested pursuant to 10 CFR 54.4(a) additional clarification for why the

in-scope boundaries for the nitrogen supply lines to 02AOV-17 and 02AOV-18 do not extend to

the actuator and justification for the boundary locations.

In its response dated February 14, 2007, the applicant stated:

The safety-related function of 02AOV-17 and 02AOV-18, to maintain Reactor

Coolant Pressure Boundary integrity, is performed with the valves closed and

does not require pneumatic pressure. Since these valves vent the reactor vessel

head to the drywell equipment drain sump, the valves would only be opened with

the reactor shutdown and depressurized. Thus, the ability to open the valves is

non-safety-related, and does not meet any scoping criteria for License Renewal.

The safety-related function of the drywell pneumatic header is to supply

pneumatic pressure to open the safety-relief valves (SRVs) when required.

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Normally closed 02SOV-17 and 02SOV-18 perform this safety-related function,

and are therefore in scope for License Renewal under 10 CFR 54.4(a)(1) with

the intended pressure boundary function. Nitrogen supply lines downstream of

the SOVs are isolated from the SRV pneumatic supply, and have no intended

function for License Renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.10-1 acceptable

because the piping in question connecting the AOVs and the SOVs has no safety-related

function. The AOVs, boundary valves to maintain RCPB integrity, during operation are passive

components in the closed position. The SOVs, which maintain instrument air system boundary

integrity, are also passive components during operation in the closed position. Therefore, the

staff's concern described in RAI 2.3.3.10-1 is resolved.

2.3.3.10.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the service, instrument, and

breathing air system components within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.11 Reactor Building Closed Loop Cooling Water

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 describes the reactor building closed loop cooling water (RBCLCW)

system, which cools equipment in the reactor building during normal plant operations and

provides a barrier between systems containing radioactive fluids and the non-radioactive SW

system pumped directly from and to the lake. The RBCLCW system consisting of a normally

independent closed loop piping arrangement is normally in operation cooling nonsafety-related

loads in the reactor building and drywell. The RBCLCW system penetrates the primary

containment in nine locations to provide cooling water to heat loads within the drywell. The

RBCLCW system has three centrifugal pumps taking suction from the reactor building cooling

water return loop for a cooling water flow. SW cools the RBCLCW heat exchangers. A surge

tank on the suction side of the pumps accommodates system volume changes, maintains static

pressure in the loop, detects gross leaks in the RBCLCW system, and allows for the addition of

makeup water. Makeup water to the RBCLCW system from the demineralized water storage

tank is supplied by a connection from the demineralized water transfer pump to the surge tank.

The RBCLCW system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related RBCLCW SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function. In addition, the RBCLCW system

performs functions that support fire protection.

LRA Tables 2.3.3-11 and 2.3.3-14-9 identify the following RBCLCW system component types

within the scope of license renewal and subject to AMR:

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" accumulator

" bolting

* filter housing

" flow element

" heat exchanger (shell)

" orifice

* piping

* pump casing

* tank

* tubing

* valve body

The RBCLCW system component intended functions within the scope of license renewal

include:

0 flow control

* pressure boundary

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.11 and 2.3.3.14, Sections 2.2 and 3.1.11 of Entergy

Report No. JAF-RPT-05-AMM30, and UFSAR Section 9.5 using the evaluation methodology

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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 of LRA Sections 2.3.3.2 and 2.3.3.14 found an area in which additional

information was necessary to complete the review of the applicant's scoping and screening

results. The applicant responded to the staff's RAI as follows.

In RAI 2.3.3.11-1 dated January 19, 2007, the staff noted that license renewal

drawing LRA-M-1 5-B, at locations C4, C7, F4, and F7, shows four RBCLCW containment

isolation valves on supply lines to the drywell. The license renewal boundary for each section of

piping ends at the AOV; however, piping and components upstream from the boundary are

labeled SEISMIC I. The staff requested pursuant to 10 CFR 54.4(a) additional information on

why the following listed pipe and component sections are not within the scope of license

renewal and justification for the boundary locations:

* license renewal drawing LRA-FM-15-B, location C4, upstream from AOV 130B through

valve 23B

* license renewal drawing LRA-FM-1 5-B, location C7, upstream from AOV 130A through

valve 23A

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license renewal drawing LRA-FM-15-B, location F4, upstream from AOV 132A through

valve 20A

license renewal drawing LRA-FM.-15-B, location F7, upstream from AOV 132B through

valve 20B

In its response dated February 14, 2007, the applicant stated that SEISMIC I boundaries are

identified uniquely on the license renewal drawings. Final safety analysis report

(FSAR)-Table 7.3-1 shows the penetration portions required to maintain pressure boundary for

containment within the system intended function boundary flags. The SEISMIC I boundary

identifies those systems that are seismically qualified category I but not necessarily required for

containment integrity. System portions included in the AMR as shown by the highlighting on the

license renewal drawing include those required to maintain the pressure boundary and ensure

containment integrity.

The applicant also stated that portions of the system beyond the containment boundary shown

as seismic I were included within the scope of license renewal in the 10 CFR 54.4(a)(2) review

but not highlighted on individual license renewal drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.11-1 acceptable

because the piping sections in question are not required to maintain containment integrity and,

therefore, not within the scope of license renewal for 10 CFR 54.4(a)(1 ) or 10 CFR 54.4(a)(3).

The staff agrees that integrity of these piping sections is not required to maintain the pressure

boundary; therefore, the staff's concern described in RAI 2.3.3.11-1 is resolved.

2.3.3.11.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and RAI responses to

determine whether the applicant failed to identify any SSCs within the scope of license renewal.

The staff finds no such omissions. In addition, the staff's review determined whether the

applicant failed to identify any components subject to an AMR. The staff finds no such

omissions. On the basis of its review, the staff concludes that there is reasonable assurance

that the applicant has adequately identified the RBCLCW'system components within the scope

of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.12 Radwaste and Plant Drains

2.3.3.12.1 Summary of Technical Information in the Application

LRA Section 2.3.3.12 describes the radwaste and plant drains system, which collects, treats,

and disposes of radioactive and potentially radioactive liquid and solid wastes in a controlled

and safe manner. These wastes are collected in sumps and drain tanks at various locations

throughout the plant and then transferred to the appropriate collection tanks in the radioactive

waste building prior to treatment, storage, and disposal. Processed liquid wastes are either

returned to the condensate system or discharged from the plant in a controlled manner. The

wastes are collected, treated, and disposed of according to their conductivity and radioactivity.

The system is divided into several subsystems so that the liquid wastes from various sources

can be segregated and processed separately. The system also drains fire suppression water

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flow in a fire so that water buildup will not impact safety-related equipment. Process solid

wastes are collected, dewatered, packaged, and stored in shielded compartments prior to

offsite shipment. The yard storm drains system collects and transfers rain runoff to the storm

sewers. The floor and roof drainage system collects and removes waste liquids from their • points of origin and to transfer them to suitable treatment and/or disposal areas in a controlled

manner. The system includes non-radioactive floor and roof drains from all areas of the plant.

The radwaste and plant drains system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related radwaste and plant

drains SSCs potentially could prevent the satisfactory accomplishment of a safety-related

function. In addition, the radwaste and plant drains system performs functions that support fire

protection.

LRA Tables 2.3.3-12, 2.3.3-14-13 and 2.3.3-14-45 identify the following radwaste and plant

drains system component system types within the scope of license renewal and subject to an

AMR:

" bolting

" filter housing

" flow element

" orifice

" piping

* pump casing

" sight glass

a steam trap

" strainer housing

* tank

a tubing

8 valve body

0 sight glass

The radwaste and plant drains system component intended function within the scope of license

renewal include:

" pressure boundary

" drainage flowpath

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.12 and 2.3.3.14, Sections 2.2, 3.1.15, 3.1.44, and 3.1.46

of Entergy Report No. JAF-RPT-05-AMM30, and UFSAR Sections 9.13, 11.2, and 11.3 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

In conducting its Tier-2 review fo the BOP two-tier review process, the staff evaluated the

system functions described in the LRA 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

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long-lived components subject to an AMR in accordance with the requirements of

10 CFR 54.21(a)(1).

The staff's review of LRA Sections 2.3.3.12 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.3.12-1 dated April 25, 2007, the staff requested additional information on the

radwaste and plant drains system and on specific components required to support the

10 CFR 54.4(a)(3) function.

In its response, by letter dated May 17, 2007, the applicant stated that the plant drains system

has a network of four-inch piping to remove approximately 100 gpm of fire fighting water in

various plant areas and buildings and that components included within the scope of license

renewal were the sump pumps, floor drain piping and valves, sump pump suction and

discharge piping and valves, and tanks that supported the function.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.12-1 acceptable

because it clearly indicated plant areas and radwaste and plant drains system components

included within the scope of 10 CFR 54.4(a)(3). The staff's concern described in RAI 2.3.3.12-1

is resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA, RAI responses, and scoping boundary drawings, to determine

whether the applicant failed to identify any SSCs within the scope of license renewal. The staff

finds no such omissions. In addition, the staff's review determined whether the applicant failed

to identify any components subject to an AMR. The staff finds no such omissions. On the basis

of its review, the staff concludes that there is reasonable assurance that the applicant has

adequately identified the radwaste and plant drains system components within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.13 Security Generator

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 describes the security generator system, equipment necessary for

maintaining site security, including the security generator, which provides necessary lighting for

certain areas.

The security generator system performs functions that support fire protection.

LRA Table 2.3.3-13 identifies the following security generator system component types within

the scope of license renewal and subject to an AMR:

" bolting

" expansion joint

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* filter housing

* heat exchanger (shell)

* heat exchanger (tubes)

* piping

* pump casing

• silencer

* •strainer

* strainer housing

* tank

* tubing

* valve body

The security generator system component intended functions within the scope of license

renewal include:

" filtration

" heat transfer

" pressure boundary

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 using the evaluation methodology described in SER

Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review fo the BOP two-tier review process, 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 reviewed components that the applicant indicated as within the scope of license

renewal to verify that the applicant had not omitted any passive and long-lived components

subject to an AMR by 10 CFR 54.21(a)(1). Based on its review, the staff found that, in addition

to the component types listed in LRA Table 2.3.3-13, an additional component, sight glass,

should have been included within the 10 CFR 54.4(a)(3) scope of license renewal. The

applicant, in Amendment 11 dated May 17, 2007, has added the component type sight glass to

LRA Table 2.3.3-13.

2.3.3.13.3 Conclusion

The staff reviewed the LRA and inspected the security generator to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the security generator system components within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.14 Miscellaneous Systems In-Scope for 10 CFR 54.4(a)(2)

LRA Section 2.3.3.14 describes the miscellaneous systems within the scope of license renewal

under 10 CFR 54.4(a)(2). Such systems interact with safety-related systems in one of two

ways: (1) a functional failure where the failure of a nonsafety-related SSC to perform its function

impacts a safety function or (2) a physical failure where a safety function is impacted by the

loss of structural or mechanical integrity of an SSC in physical proximity to a safety-related

component.

LRA Section 2.3.3.14 states that functional failures of nonsafety-related SSCs which could

impact a safety function are identified in previous LRA sections.

LRA Table 2.3.3.14-A shows systems within the scope of license renewal with potential for

physical interactions with safety-related components. Of these systems, the following are not

described elsewhere in the LRA:

* reactor water cleanup

* extraction steam

* decay heat removal (DHR)

" feedwater heater vents and drains

" circulating water

* turbine building closed loop cooling (TBCLC)

" vacuum priming and air removal

* turbine lube oil

• secondary plant drains

* raw water treatment

" contaminated equipment drains

• auxiliary gas treatment

* plumbing, sanitary and lab

" city water

" auxiliary boiler and accessories

" main turbine generator

" sample system

" steam seal

2.3.3.14A Reactor Water Cleanup

2.3.3.14A.1 Summary of Technical Information

The RWCU system maintains high reactor water purity to limit chemical and corrosive action,

fouling, and deposition on heat transfer surfaces. The RWCU system removes corrosion

products to limit impurities for neutron activation and resultant radiation from deposition of

corrosion products. The system also decreases reactor coolant system inventory during heatup.

The failure of nonsafety-related RWCU SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function. In addition, the RWCU system performs functions

that support fire protection.

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LRA Table 2.3.3-14-6 identifies the following RWCU system component types within the scope

of license renewal and subject to an AMR:

* bolting

* demineralizer

* flow element

* 'heat exchanger (shell)

* orifice

* piping

* pump casing

* sight glass

* strainer housing

* tank

• thermowell

* tubing

* valve body

The RWCU system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.14A.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.

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).

After examining the IPE results to confirm that the RWCU system poses no significant risk, the

staff completed a Tier-1 review, which does not require detailed boundary drawings. The

system is not a dominant contributor to core damage frequency, nor is it involved in the

dominant initiating events.

2.3.3.14A.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the miscellaneous 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 those subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.14B Extraction Steam

2.3.3.14B.1 Summary of Technical Information

The extraction steam system transports steam to components of the steam and power

conversion system. The extraction steam system supplies steam from the turbine extraction

points to loads like the feedwater heaters and reactor feed pump turbines. The extraction steam

system includes the moisture separator reheaters and the steam reboiler system.

The failure of nonsafety-related extraction steam SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-17 identifies the following extraction steam system component types within

the scope of license renewal and subject to an AMR:

" bolting

• expansion joint

" flow element

• heat exchanger (shell)

" orifice

" piping

" strainer housing

" tank

* thermowell

* tubing

* valve body

The extraction steam system component intended function within the scope of license renewal

is to provide a pressure boundary.

2.3.3.14B.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 9.18, 10.1, 10.2 and 10.8 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

The staff verified that the extraction steam system poses no significant risk by examining the

IPE results, and therefore, performed a Tier-1 review which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

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).

2.3.3.14B.3 Conclusion

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The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the extraction steam system

components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14C Decay Heat Removal

2.3.3.14C.1 Summary of Technical Information

The DHR system provides an alternate means of decay heat removal from the spent fuel pool.

The DHR system can also cool the reactor core when the reactor pressure vessel head has

been removed, the reactor cavity flooded, and the fuel transfer gates removed by utilizing

natural convection currents established between the spent fuel pool and the reactor cavity.

The failure of nonsafety-related DHR SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-18 identifies the following DHR system component types within the scope

of license renewal and subject to an AMR:

" bolting

* flow element

* heat exchanger (shell)

" piping

" pump casing

* strainer housing

* tubing

* valve body

The DHR system component intended function within the scope of license renewal is to provide

a pressure boundary.

2.3.3.14C.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.

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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After examining the IPE results to confirm that the DHR steam system poses no significant risk,

the staff completed a Tier-1 review, which does not require detailed boundary drawings. The

system is not a dominant contributor to core damage frequency, nor is it involved in the

dominant initiating events.

2.3.3.14C.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the miscellaneous 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 those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.14D Feedwater Heater Vents and Drains

2.3.3.14D.1 Summary of Technical Information

The feedwater heater vents and drains system supports feedwater heating in the condensate

system. The system consists of the piping, valves, instruments, and controls that maintain

appropriate shell side levels in the feedwater heaters. Drains cascade from the highest to

lowest pressure heater and to the main condenser. Heater vents are also connected to the

condenser.

The failure of nonsafety-related feedwater heater vents and drains SSCs potentially could

prevent the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-21 identifies the following feedwater heater vents and drains system

component types within the scope of license renewal and subject to an AMR:

" bolting

" orifice

* piping

" sight glass

" thermowell

* tubing

* valve body

The feedwater heater vents and drains system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.3.14D.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 10.8 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the feedwater heater vents and drains system poses no significant risk by

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examining the IPE results, and therefore, performed a Tier-1 review which does not require

detailed boundary drawings. The system is not a dominant contributor to core damage

frequency, nor is it involved in the dominant initiating events.

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).

2.3.3.14D.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the feedwater heater vents

and drains system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14E Circulating Water

2.3.3.14E.1 Summary of Technical Information

The circulating water system supplies the main condenser continuously with cooling water to

remove heat rejected by the turbine exhaust and turbine bypass steam as well as from other

exhausts over the full range of operating loads.

The failure of nonsafety-related circulating water SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-22 identifies the following circulating water system component types within

the scope of license renewal and subject to an AMR:

* bolting

* piping

* pump casing

* tank

* tubing

* valve body

The circulating water system component intended function within the scope of license renewal

is to provide a pressure boundary.

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2.3.3.14E.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 10.6 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).

The staff's review of LRA Section 2.3.3.14 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant' responded to the staff's RAI as follows.

In RAI 2.3.3.14-2, dated April 25, 2007, the staff requested additional information on a number

of systems included in LRA Section 2.3.14, including the circulating water system. Specifically

the staff asked the applicant to indicate the circulating water system parts included within the

10 CFR 54.4(a)(2) scope of license renewal.

In its response dated May 17, 2007, the applicant indicated that it had used the component

database for the locations of the circulating water system components. Potential

10 CFR 54.4(a)(2) passive mechanical components in the system are located in the screenwell

house and turbine building. All system components except those in the turbine building in areas

below elevation 260 and on elevation 260 outside grid coordinates 260-8D through 13G and in

the screenwell pump house below elevations 255 or areas on elevation 272 outside building

grid coordinates SW272-25A and 26A are included within the 10 CFR 54.4(a)(2) scope of

license renewal. There is no safety-related equipment in the excluded areas and, thus, no

potential for spatial interaction of nonsafety-related with safety-related SSCs; therefore, the

applicant's exclusion of the components in these areas is justified.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable

because it clearly indicated the plant areas and circulating water system components included

within the 10 CFR 54.4(a)(2) scope of license renewal. The staff's concern about the circulating

water system described in RAI 2.3.3.14-2 is resolved.

2.3.3.14E.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

circulating water system components 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 those subject to an AMR, as

required by 10 CFR 54.21(a)(1).

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2.3.3.14F Turbine Building Closed Loop Cooling

2.3.3.14F.1 Summary of Technical Information

The TBCLC system cools auxiliary equipment in the turbine building and in the radioactive

waste building. It also provides makeup seal water to the condenser air removal pumps and the

condenser water box vacuum priming pumps.

The failure of nonsafety-related TBCLC SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-23 identifies the following TBCLC system component types within the

scope of license renewal and subject to an AMR:

" bolting

• piping

" strainer housing

• tank

" thermowell

• tubing

" valve body

The TBCLC system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.14F.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 9.6 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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 of LRA Section 2.3.3.14 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.3.14-2 dated April 25, 2007, the staff requested additional information on a number

of systems included in LRA Section 2.3.14, including the TBCLC system. Specifically the staff

asked for the TBCLC system part included within the scope of license renewal and why the

TBCLC pumps and heat exchangers were not subject to an AMR.

In its response dated May 17, 2007, the applicant indicated that it had used the component

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database for locations-of TBCLC components. Potential 10 CFR 54.4(a)(2) passive mechanical

components in the system are located in the turbine building, auxiliary boiler room, and

radwaste building. Components in the auxiliary boiler building, the radwaste building, and

turbine building in areas below elevation 260 and on elevation 260 outside grid coordinates

260-8D through 13G are not within the scope of license renewal as there are no safety-related

components in these buildings or areas. The applicant stated that the TBCLC pumps and heat

exchangers in turbine building areas with a floor elevation below 260 were located in an area

with no safety-related equipment or components and so excluded from the scope of license

renewal.

Based on its review, the staff finds the applicant's acceptable because it clearly indicated the

plant areas'and components of the TBCLC system and justified the exclusion of the TBCLC

pumps and heat exchangers. The staff's concern about the TBCLC system described in

RAI 2.3.3.14-2 is resolved.

2.3.3.14F.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

turbine building closed loop cooling system components 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 those

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.14G Vacuum Priming and Air Removal

2.3.3.14G.1 Summary of Technical Information

The vacuum priming and air removal system removes all air and noncondensable gases from

the condenser. The system also processes turbine gland seal leakoff.

The failure of nonsafety-related vacuum priming and air removal SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-24 identifies the following vacuum priming and air removal system

component types within the scope of license renewal and subject to an AMR:

• bolting

" heat exchanger (shell)

• piping

* pump casing * sight glass

" tank

• tubing

" valve body

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The vacuum priming and air removal system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.3.14G.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 10.4 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the vacuum priming and air removal system poses no significant risk by

examining the IPE results, and therefore, performed a Tier-1 review which does not require

detailed boundary drawings. The system is not a dominant contributor to core damage

frequency, nor is it involved in the dominant initiating events.

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).

2.3.3.14G.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the vacuum priming and air

removal system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14H Turbine Lube Oil

2.3.3.14H.1 Summary of Technical Information

The turbine lube oil system provides clean lubricating oil to the lubrication oil reservoirs of the

main turbine generator, the reactor feed pump turbines, and the main generator shaft hydrogen

seals. The turbine lube oil system includes the main turbine oil reservoir, a turbine oil

conditioner, clean, dirty, and waste oil storage tanks, and the interconnecting piping, pumps,

valves, instrumentation, and controls.

The failure of nonsafety-related turbine lube oil SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

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LRA Table 2.3.3-14-26 identifies the following turbine lube oil system component types within

the scope of license renewal and subject to an AMR:

* bolting

* piping

* pump casing

* sight glass

" strainer housing

" tank

" thermowell

" tubing

• valve body

The turbine lube oil system component intended function within the scope of license renewal is

to provide a pressure boundary.

2.3.3.14H.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 verified that the turbine lube oil system poses no significant risk by examining the IPE

results, and therefore, performed a Tier-1 review which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

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).

2.3.3.14H.3 Conclusion

The staff reviewed the LRA and to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staffs

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the turbine lube oil system

components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.3.141 Secondary Plant Drains

2.3.3.141.1 Summary of Technical Information

The secondary plant drains system provides a drain flowpath from steam and power conversion

system components to the main condenser and includes piping, valves, instrumentation, and

controls to handle drainage from various systems including MS, extraction steam, and vacuum

priming and air removal systems.

The failure of nonsafety-related secondary plant drains SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-27 identifies the following secondary plant drains system component types

within the scope of license renewal and subject to an AMR:

* bolting

* orifice

" piping

* strainer housing

* thermowell

* tubing

• valve body

The secondary plant drains system component intended function within the scope of license

renewal is to provide a pressure boundary.

2.3.3.141.2 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 verified that the secondary plant drains system poses no significant risk by examining

the IPE results, and therefore, performed a Tier-1 review which does not require detailed

boundary drawings. The system is not a dominant contributor to core damage frequency, nor is

it involved in the dominant initiating events.

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).

2.3.3.141.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

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The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the secondary plant drains

system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14J Raw Water Treatment

2.3.3.14J.1 Summary of Technical Information

The raw water treatment system supplies treated water suitable for plant makeup and other

demineralized water requirements.

The failure of nonsafety-related raw water treatment SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-28 identifies the following raw water treatment system component types

within the scope of license renewal and subject to an AMR:

" bolting

• filter housing

" orifice

" piping

" pump casing

* sight glass

" strainer housing

" tubing

* valve body

The raw water treatment system component intended function within the scope of license

renewal is to provide a pressure boundary.

2.3.3.14J.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 9.10 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the raw water treatment system poses no significant risk by examining the

IPE results, and therefore, performed a Tier-1 review which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

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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2.3.3.14J.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the raw water treatment

system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14K Contaminated Equipment Drains

2.3.3.14K.1 Summary of Technical Information

The contaminated equipment drains system collects and transfers waste liquids to suitable

treatment or disposal areas in a controlled manner. The system consists of piping and

components which drain contaminated or potentially contaminated waste from equipment and

floor drains to the radioactive waste system for processing.

The failure of nonsafety-related contaminated equipment drains SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-29 identifies the following contaminated equipment drains system

component types within the scope of license renewal and subject to an AMR:

" bolting

" piping

" sight glass

" valve body

The contaminated equipment drains system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.3.14K.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14, UFSAR Sections 9.13, 9.14 and 11.2, and Entergy

Report No. JAF-RPT-05-AMM30, Sections 2.2 and 3.1.32, using the evaluation methodology

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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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The staff's review of LRA Section 2.3.3.14 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.3.14-2 dated April 25, 2007, the staff requested additional information on a number

of systems in LRA Section 2.3.3.14, including the contaminated equipment drain system.

Specifically the staff asked which part of the contaminated equipment drain system was within

the scope of license renewal.

In its response dated May 17, 2007, the applicant indicated that it had used the component

database for the locations of the contaminated equipment drain system components. Potential

10 CFR 54.4(a)(2) passive mechanical components in the system are located in the reactor

building.

As the complete system is in the reactor building, where all SSCs are within the

10 CFR 54.4(a)(2) scope of license renewal, all contaminated equipment drain system

components are within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable. The

staff's concern about the contaminated equipment drain system described in RAI 2.3.3.14-2 is

resolved.

2.3.3.14K.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

contaminated equipment drain system components 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 those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.14L Auxiliary Gas Treatment

2.3.3.14L.1 Summary of Technical Information

The auxiliary gas treatment system supports the reactor vessel head removal by processing

radioactive gases that accumulate under the reactor vessel head during plant outages. During

outages the system also uses portable hoses or ducts to remove radioactive gasses around

contaminated equipment. A removable duct section connects the reactor vessel head to the

auxiliary gas treatment system consisting of a demister, high-efficiency filters, charcoal filter,

and a fan. The processed gas then is discharged to the reactor building ventilation system

exhaust or to the SGT system.

The failure of nonsafety-related auxiliary gas treatment SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

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LRA Table 2.3.3-14-31 identifies the following auxiliary gas treatment system component types

within the scope of license renewal and subject to an AMR:

" bolting

" damper housing

* duct

The auxiliary gas treatment system component intended function within the scope of license

renewal is to provide a pressure boundary.

2.3.3.14L.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.

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).

After examining the IPE results to confirm that the auxiliary gas treatment system poses no

significant risk, the staff completed a Tier-1 review, which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

2.3.3.14L.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the miscellaneous 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 those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.14M Plumbing, Sanitary, and Lab

2.3.3.14M.1 Summary of Technical Information

The plumbing, sanitary, and lab system provides drinking water supplies and disposes of

sanitary wastes during normal plant operation. This system includes the domestic water storage

tank, potable water pump, potable water distribution piping, the shower waste storage tank and

pump, and the laboratory vacuum equipment.

The failure of nonsafety-related plumbing, sanitary, and lab SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

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LRA Table 2.3.3-14-37 identifies the following plumbing, sanitary, and lab system component

types within the scope of license renewal and subject to an AMR:

" bolting

• heat exchanger (shell)

* piping

" strainer housing

" valve body

The plumbing, sanitary, and lab system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.3.14M.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 9.12 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the plumbing, sanitary, and lab system poses no significant risk by

examining the IPE results, and therefore, performed a Tier-1 review which does not require

detailed boundary drawings. The system is not a dominant contributor to core damage

frequency, nor is it involved in the dominant initiating events.

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).

2.3.3.14M.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the plumbing, sanitary, and

lab system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.14N City Water

2.3.3.14N.1 Summary of Technical Information

The city water system distributes potable water to various locations around the plant site. The

system consists of the piping and valves from the Oswego water supply to distribution systems

in buildings around the site and to such others as the potable water and water treatment

systems.

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The failure of nonsafety-related city water SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-39 identifies the following city water system component types within the

scope of license renewal and subject to an AMR:

* bolting

" piping

" valve body

The city water system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.14N.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 verified that the city water steam system poses no significant risk by examining the

IPE results, and therefore, performed a Tier-1 review which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

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).

2.3.3.14N.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the city water system

components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.140 Auxiliary Boiler and Accessories

2.3.3.140.1 Summary of Technical Information

The auxiliary boiler and accessories system heats the plant building spaces during planned

operation by a forced-circulation hot water system for recirculation air heating and a hot

water-ethylene glycol system for heating outside air introduced into ventilation systems. The

plant heating system consists of two package hot water boilers, two hot water circulating

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pumps, three hot water-glycol circulating pumps, two fuel oil transfer pumps, one

170,000-gallon fuel storage tank, two compression tanks, piping, valves, combustion controls,

and instrumentation.

The failure of nonsafety-related auxiliary boiler and accessories SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-40 identifies the following auxiliary boiler and accessories system

component types within the scope of license renewal and subject to an AMR:

° bolting

" flow element

* piping

" tubing

" valve body

The auxiliary boiler and accessories system component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.3.140.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 9.9.3.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the auxiliary boiler and accessories system poses no significant risk by

examining the IPE results, and therefore, performed a Tier-1 review which does not require

detailed boundary drawings. The system is not a dominant contributor to core damage

frequency, nor is it involved in the dominant initiating events.

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).

2.3.3.140.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the auxiliary boiler and

accessories 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 those subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.14P Main Turbine Generator

2.3.3.14P.1 Summary of Technical Information

The main turbine generator system receives steam from the boiling water reactor, economically

converting a portion of the thermal energy in the steam to electric energy and extracting steam

for feedwater heating.

The failure of nonsafety-related main turbine generator SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-14-42 identifies the following main turbine generator system component types

within the scope of license renewal and subject to an AMR:

" bolting

" filter housing

" heat exchanger (shell)

" piping

" pump casing

" sight glass

• strainer housing

* tank

* thermowell

* tubing

* turbine casing

* valve body

The main turbine generator system component intended function within the scope of license

renewal is to provide a pressure boundary.

2.3.3.14P.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 10.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review of the BOP two-tier review process, 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 of LRA Section 2.3.3.14 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.3.14-2 dated April 25, 2007, the staff requested additional information on a number

of systems in LRA Section 2.3.3.14, including the main turbine generator system. Specifically

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the staff asked which part of the main turbine generator system was within the scope of license

renewal.

In its response dated May 17, 2007, the applicant indicated that it had used the component

database for the locations of the main turbine generator system components. Potential

10 CFR 54.4(a)(2) passive mechanical components in the system are located in the turbine

building, and all passive components in the system were within the 10 CFR 54.4(a)(2) scope of

license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable

because it clarified that all main turbine generator system components are within the scope of

license renewal. The staff's concern about the main turbine generator system described in

RAI 2.3.3.14-2 is resolved.

2.3.3.14P.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staffs review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

main turbine generator system components 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 those subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.14Q Sample System

2.3.3.14Q. 1 Summary of Technical Information

The sample system monitors the operational performance of plant equipment. Samples are

taken from various streams and locations. There are two sample sinks, one in the reactor

building and one in the radioactive waste building. Most samples are sent to these sinks to

facilitate sampling and reduce exposure to plant personnel. Samples are taken to the laboratory

for appropriate analysis. In addition, continuous automatic monitoring and alarm of undesirable

conditions uses in-line detectors when necessary.

The failure of nonsafety-related sample system SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-43 identifies the following sample system component types within the

scope of license renewal and subject to an AMR:

* bolting

* heat exchanger (tubes)

* piping

* pump casing

* sight glass

* tubing

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0 valve body

The sample system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.14Q.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.

In conducting its Tier-2 review of the BOP two-tier process, 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 of LRA Section 2.3.3.14 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.3.14-2 dated April 25, 2007, the staff requested additional information on a number

of systems in LRA Section 2.3.3.14, including the sample system. Specifically the staff asked

which part of the sample system was within the scope of license renewal.

In its response dated May 17, 2007, the applicant indicated that it had used the component

database for the locations of the sample system components. The applicant also indicated that

the potential 10 CFR 54.4(a)(2) passive mechanical components in the system are located in

the turbine building but that all system passive components were within the 10 CFR 54.4(a)(2)

scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable

because it clarified that all sample system components are within the scope of license renewal.

The staffs concern about the sample system described in RAI 2.3.3.14-2 is resolved.

2.3.3.14Q.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

sample system components 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 those subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.3.14R Steam Seal

2.3.3.14R.1 Summary of Technical Information

The steam seal system prevents steam leakage out of and air leakage into the turbine or

condenser. The system consists of the steam seal regulator, steam seal header, and piping to

the steam packing exhauster. Steam is supplied to the steam seal system from the gland seal

reboiler system. Sealing steam is supplied to the sub-atmospheric glands of the low-pressure

turbine and the reactor feed pump turbine from the steam seal header. The outer ends of all

glands are routed to the steam packing exhauster, which is maintained at a slight vacuum by

the exhaust blowers.

The failure of nonsafety-related steam seal SSCs potentially could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-14-44 identifies the following steam seal system component types within the

scope of license renewal and subject to an AMR:

* bolting

" piping

" tubing

* valve body

The steam seal system component intended function within the scope of license renewal is to

provide a pressure boundary.

2.3.3.14R.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and the UFSAR using the evaluation methodology

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff verified that the steam seal system poses no significant risk by examining the IPE

results, and therefore, performed a Tier-1 review which does not require detailed boundary

drawings. The system is not a dominant contributor to core damage frequency, nor is it involved

in the dominant initiating events.

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).

2.3.3.14R.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

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The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the steam seal system

components 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 those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

The remaining systems shown in LRA Table 2.3.3.14-A as within the scope of license renewal

with potential for physical interaction with safety-related components are addressed elsewhere

in other LRA sections listed here:

0 2.3.1 CRD

* 2.3.1 reactor coolant

a 2.3.2.1 RHR

0 2.3.2.2 CS

0 2.3.2.4 HPCI

0 2.3.2.5 RCIC

0 2.3.2.6 gas-handling

0 2.3.2.7 primary containment

* 2.3.3.1 SLC

* 2.3.3.2 SW

* 2.3.3.3 EDG

* 2.3.3.5 FP

* 2.3.3.7 administration building ventilation and cooling

* 2.3.3.7 drywell ventilation and cooling

* 2.3.3.7 process radiation monitors

* 2.3.3.7 reactor building ventilation

* 2.3.3.7 screenwell and water treatment ventilation and cooling

" 2.3.3.7 turbine building ventilation

" 2.3.3.8 CP, CAD, and PASS

" 2.3.3.9 FPCC

" 2.3.3.10 service, instrument, and breathing air

" 2.3.3.11 RBCLCW

" 2.3.3.12 radwaste

* 2.3.4.1 condensate

" 2.3.4.2 MS

" 2.3.4.3 feedwater

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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

" 2.3.4.2 main steam

" 2.3.4.3 feedwater

The staff's findings on review of LRA Sections 2.3.4.1 - 2.3.4.3 are in SER Sections 2.3.4.1 -

2.3.4.3, respectively.

2.3.4.1 Condensate

2.3.4.1.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the condensate system, which heats and supplies feedwater to

the reactor. The condensate tanks supply water to the HPCI and RCIC systems. The

condensate system includes main condensers, condensate pumps, condensate demineralizers,

condensate booster pumps, feedwater heaters, CSTs, and condensate transfer pumps.

Condensate demineralizers maintain the required purity of feedwater to the reactor by removing

suspended and dissolved solids and fission, activation, and corrosion products The full-flow,

deep bed condensate demineralizer system consists of eight (one spare) mixed-bed ion

exchangers and an external chemical regeneration facility. The CSTs receive system reject flow

and provide condensate for any continuous or intermittent batch-type services, including plant

system makeup and suppression pool makeup. Two condensate transfer pumps supply

condensate to various loads, for which suction connections above the HPCI and RCIC suctions

to the CSTs provide a 100,000-gallon reserve in each tank for the ECCS. The lower half of

each tank is below ground level for tornado and SEISMIC protection of the 100,000-gallon

reserve storage capacity. The condensate tanks are the preferred supply of water to the HPCI

and RCIC systems while torus water storage provides a safety-related backup water supply.

The condensate has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related condensate SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the condensate system

performs functions that support fire protection and SBO.

LRA Tables 2.3.4-1 and 2.3.3-14-19 identify the following condensate system component types

within the scope of license renewal and subject to an AMR:

" bolting

" flow element

" heat exchanger (shell)

* orifice

* piping

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• .pump casing

* screen

* strainer housing

* tank

* thermowell

* tubing

* valve body

The condensate system component intended functions within the scope of license renewal

include:

" filtration

" pressure boundary

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.14 and 2.3.4.1 and UFSAR Sections 10.3, 10.7, 10.8,

and 10.9 using the evaluation methodology described in SER Section 2.3 and the guidance in

SRP-LR Section 2.3.

In conducting its Tier-2 review fo the BOP two-tier review process, 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 of LRA Sections 2.3.3.2 and 2.3.3.14 found areas in which additional

information was necessary to complete the review of the applicant's scoping and screening

results. The applicant responded to the staff's RAIs as follows.

In RAI 2.3.4.1-1 dated January 19, 2007, the staff noted that two condensate storage tanks

were the preferred source of water to the HPCI and RCIC systems during postulated small pipe

breaks. Each tank must have a reserve storage capacity of 100,000 gallons and be capable of

isolation from other systems. The tanks are designed for the required flow even if their portions

above ground are destroyed by tornado or earthquake. License renewal drawing LRA-FM-33-D

indicates the nozzle penetration at the storage tanks as the license renewal boundary for

system piping other than HPCI and RCIC with a possibility of a tank leak not capable of

isolation. The staff requested pursuant to 10 CFR 54.4(a) additional information on why the

piping from nozzle penetrations to the nearest isolation valves is not within the scope for license

renewal and justification for the boundary locations.

In its response dated February 14, 2007, the applicant stated that the schematic license

renewal drawing LRA-FM-33-D does not show actual nozzle locations. The tank nozzles in

question (N-2, N-3, N-1 1, N-7, N-9, N-8, C-3, N-5, N-1 0, and C-2 on tank TK-1 2A and N-2, N-3,

N-1 1, N-7, N-9, N-8, C-3, N-5, N-1 0, and C-2 on tank TK-1 2B) are located in the upper half of

the tank (above the required reserve supply) and their failure would not impact condensate

storage tank ability to perform the intended function. Therefore, the nozzles, valves, and piping

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in question are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-1 acceptable

because it confirmed that failure of these components will not prevent the tanks from retaining

the required minimum storage capacity of 100,000 gallons. Therefore, the staff's concern

described in RAI 2.3.4.1-1 is resolved.

In RAI 2.3.4.1-2 dated January 19, 2007, the staff noted that two condensate storage tanks are

the preferred sources of water to the HPCI and RCIC systems during postulated small pipe

breaks. The tanks are designed for the required flow even if their portions above ground are

destroyed by tornado or earthquake. License renewal drawing LRA-FM-25-A indicates the

nozzle penetrations at the storage tanks as the license renewal boundaries on the crosstie line

for the two tanks with the possibility of a tank leak not capable of isolation. The staff requested

pursuant to 10 CFR 54.4(a) additional information on why the piping from N-1 to valve 02A on

condensate storage tank A and piping from N-1 to valve 02B on condensate storage tank B are

not within the scope of license renewal and justification for the boundary locations.

In its response dated February 14, 2007, the applicant stated that these nozzles (nozzle N-1 on

CST A and CST B) are located well above the tank portion required to maintain the minimum

volume for supply to the HPCI and RCIC pumps. Therefore, pressure boundary integrity of

these lines is not required and they are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-2 acceptable

because it confirmed that failure of these components will not prevent the tanks from retaining

the required minimum storage capacity of 100,000 gallons. Therefore, the staff's concern

described in RAI 2.3.4.1-2 is resolved.

2.3.4.1.3 Conclusion

The staff reviewed the LRA, scoping boundary drawings, the response to the requested

inspection item, and RAI responses to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any components subject to an

AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified the condensate

system components within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.2 Main Steam

2.3.4.2.1 Summary of Technical Information in the Application

LRA Section 2.3.4.2 describes the MS system, which carries steam from the reactor vessel

through the primary containment to the MS turbine and supplies steam to the HPCl and RCIC

turbines when required. The MS leak collection system collects and processes leakage across

the seats of the MS isolation valves and stem packing leakage from the MS isolation valves

outside containment following a design-basis LOCA. The MS leak collection system monitors

and routes the non-condensables of the packing gland leak-off of outboard MS isolation valves

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to the SGT system, which processes effluent of the MS leak collection system and exhausts it

through the stack.

The MS system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related MS SSCs potentially could prevent the

satisfactory accomplishment of a safety-related function. In addition, the MS system performs

functions that support fire protection and SBO.

The MS system component types within the scope of license renewal and subject to an AMR

are included in LRA Sections 2.3.3.10, 2.3.2.6, 2.3.1, and 2.3.3.14. LRA Table 2.3.3-14-16

identifies the following MS system nonsafety-related component types within the scope of

license renewal and subject to an AMR:

" bolting

* piping

* strainer housing

" thermowell

" tubing

" valve body

The MS system nonsafety-related component intended function within the scope of license

renewal is to provide a pressure boundary.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.14 and 2.3.4.2 and UFSAR Sections 4.6, 4.11, 6.4.1,

9.19, and 10.5 using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section 2.3.

In conducting its Tier-2 review for the BOP two-tier review process, 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 of LRA Section 2.3.4.2.2 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as follows.

In RAI 2.3.4-1 dated April 25, 2007, the staff requested additional information on the scoping

and screening of the MS and the feedwater systems. LRA Section 2.3.4.2.2 does not indicate

clearly the specific MS components within the scope of license renewal but indicates that

system components were included in the scoping of systems addressed in other LRA sections.

The staff asked which MS components were within the scope of license renewal and where in

the LRA they were evaluated.

In its response dated May 17, 2007, the applicant indicated the MS components within the

scope of license renewal, the class 1 MS components evaluated with the RCS, the MSLCS

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components with the SGT system, and the MSIV accumulators with the instrument air system.

The applicant also indicated that all of the system components inside the primary containment,

reactor building, and turbine building except for areas below elevation 260 or on elevation 260

outside coordinates 260-8D throughl3G were within the 10 CFR 54.4(a)(2) scope of license

renewal. Components in turbine building areas below elevation 260 or on elevation 260 outside

coordinates 260-8D throughl3G were excluded because there are no safety-related

components.

Based on its review, the staff finds the applicant's response to RAI 2.3.4-1 acceptable because

it specified the MS system portions within the 10 CFR 54.4(a)(2) scope of license renewal and

adequately justified the excluded components. The staff's concern described in RAI 2.3.4-1 is

resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA, the response to the requested inspection item, and scoping

boundary drawings to determine whether the applicant failed to identify any SSCs within the

scope of license renewal. The staff finds no such omissions. In addition, the staffs review

determined whether the applicant failed to identify any components subject to an AMR. The

staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the MS system components

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.3 Feedwater

2.3.4.3.1 Summary of Technical Information in the Application

LRA Section 2.3.4.3 describes the feedwater system, which heats and supplies feedwater to

the reactor. The feedwater system includes the zinc injection system, which through addition of

small amounts of ionic zinc reduces hot spots and post-shutdown radiation levels in the reactor

coolant system due to reduced cobalt activation. The system consists of skid-mounted injection

equipment connected to the reactor feedwater pump piping by a bypass recirculation loop

around the feedwater pumps.

The feedwater system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related feedwater SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function.

The feedwater system component types within the scope of license renewal and subject to an

AMR are included in LRA Sections 2.3.1 and 2.3.3.14. LRA Table 2.3.3-14-20 identifies the

following feedwater system nonsafety-related component types within the scope of license

renewal and subject to an AMR:

• bolting

• orifice

• piping

* thermowell

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" tubing * valve body

The feedwater system nonsafety-related component intended function within the scope of

license renewal is to provide a pressure boundary.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.14 and 2.3.4.3 and UFSAR Sections 9.21 and 10.8

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

In conducting its Tier-2 review fo the BOP two-tier review process, 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 staffs review of LRA Section 2.3.4.2.2 found an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to staff's RAI as follows.

In RAI 2.3.4-1 dated April 25, 2007, the staff requested additional information on the scoping

and screening of the MS and the feedwater systems. LRA Section 2.3.4.2.2 does not indicate

clearly the specific MS components within the scope of license renewal but indicates that

system components were included in the scoping of systems addressed in other LRA sections.

The staff asked which MS components were within the scope of license renewal and where in

the LRA they were evaluated.

In its response dated May 17, 2007, the applicant explained that indicated the feedwater system

components within the 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) scope of license renewal are

shown on license renewal drawing LRA-FM-34A, and prefixed with "34" or "FWS," designations

for the feedwater system. The applicant indicated that the components highlighted were

evaluated in the RCS section. The applicant also indicated that the system components in the

turbine building, except for areas below elevation 260 or on elevation 260 outside coordinates

260-8D throughl3G, were within the 10 CFR 54.4(a)(2) scope of license renewal. Components

in turbine building areas below elevation 260 or on elevation 260 outside coordinates 260-8D

throughl3G were excluded because there are no safety-related components in these areas.

Based on its review, the staff finds the applicants response to RAI 2.3.4-1 acceptable because

it specified the feedwater system portions within the 10 CFR 54.4(a)(2) scope of license

renewal and adequately justified the excluded components. The staff's concern described in

RAI 2.3.4-1 is resolved.

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2.3.4.3.3 Conclusion

The staff reviewed the LRA, the response to the requested inspection item, and scoping

boundary drawings to determine whether the applicant failed to identify any SSCs within the

scope of license renewal. The staff finds no such omissions. In addition, the staff's review

determined whether the applicant failed to identify any components subject to an AMR. The

staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the feedwater system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4 Scoping and Screening Results: Structures

This section documents the staffs review of the applicant's scoping and screening results for

structures. Specifically, this section discusses:

* reactor building and primary containment

" water control structures

" turbine building complex 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

structures and 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 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 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 component

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

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 SOs 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

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these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested

additional information to resolve any omissions or discrepancies identified.

2.4.1 Reactor Building and Primary Containment

2.4.1.1 Summary of Technical Information in the Application

LRA Section 2.4.1 describes the reactor building and primary containment. The reactor building

totally encloses the primary containment, the refueling and reactor servicing areas, the new and

spent fuel storage facilities, and other reactor auxiliary systems. It serves as a containment

during reactor refueling and maintenance operations when the primary containment is open and

as an additional barrier when the primary containment is functional.

The reactor building structure is SEISMIC Class I, constructed of monolithic reinforced concrete

floors and walls to the refueling level. A reinforced concrete mat placed in an excavation cut out

of bedrock supports the reactor building structure and prevents settlement. The reactor building

structural steel includes floor framing for platforms inside the drywell and suppression chamber.

The primary containment limits the release of fission products in a postulated DBA so that

offsite doses do not exceed 10 CFR Part 100 guideline values. The primary containment is a

Mark I low-leakage pressure suppression containment housing the reactor vessel, the reactor

recirculation loops, and other branch connections of the reactor coolant system. Major

components of primary containment include a drywell, a pressure suppression chamber, and

the connecting vent system between the drywell and torus. The drywell surrounds the reactor

vessel, connects to the reactor building along its lower portion, and is laterally supported by the

building along its upper portion. The primary containment consists of the drywell, torus, inner

refueling bellows, and primary shield wall.

The drywell is a carbon steel structure enclosed in reinforced concrete for shielding. It houses

the reactor vessel and its components. The torus is a carbon steel pressure vessel anchored to

and supported by the reinforced concrete foundation slab of the reactor building. The inner

refueling bellows seal between the reactor vessel flange and the surrounding drywell permits

flooding of the space above the vessel during refueling. The refueling bellows consists of a

stainless steel bellows, backing plates, a spring seal, and removable guard rings. The primary

shield wall is a high-density concrete cylinder surrounding the vessel to attenuate neutron and

gamma radiation from the reactor, to allow access and maintenance of the drywell, and to limit

damage from radiation exposure to area components.

The reactor building and the primary containment have safety-related components relied upon

to remain functional during and following DBEs. The failure of nonsafety-related reactor building

and primary containment SSCs potentially could prevent the satisfactory accomplishment of a

safety-related function. In addition, the reactor building and the primary containment perform

functions that support fire protection and SBO.

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LRA Table 2.4-1 identifies the following reactor building and primary containment component

types within the scope of license renewal and subject to an AMR:

* steel

• other metals

" concrete

The reactor building and primary containment component intended functions within the scope of

license renewal include:

" shelter or protection to safety-related equipment, including radiation shielding and pipe

whip restraint

" rated fire barrier to confine or retard a fire from spreading

" protective barrier for flood events

" heat sink during SBO or DBA

" missile barrier

" pressure boundary

" structural or functional support to nonsafety-related equipment whose failure could

impact safety-related equipment

" structural or functional support for safety-related equipment

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and UFSAR Sections 5.1.2, 5.1.3, 5.2, 5.3, 12.3.1, and

12.4.5. using the evaluation methodology described in SER Section 2.4 and the guidance in

SRP-LR Section 2.4, "Scoping and Screening Results: Structures."

During its review, the staff evaluated the structural component functions described in the LRA

and 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 of LRA Section 2.4.1 found areas in which additional information was

necessary to complete the evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as follows.

LRA Section 2.4-1, "Reactor Building and Primary Containment," under Inner Refueling Bellows

and Bulkhead Assembly does not state the makeup of the bulkhead assembly clearly. In

RAI 2.4.1-1 dated November 29, 2006, the staff requested a list of bulkhead assembly

components within the scope of license renewal and a drawing of the bulkhead assembly.

In its response dated December 28, 2006, the applicant stated that bulkhead assembly

components are not within the scope of license renewal. They are nonsafety-related and are

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not required to demonstrate compliance with 10 CFR 54.4(a)(3). The applicant indicated that

LRA Table 3.5.2-1, page 3.5-58 line item "inner refueling bellows" and the corresponding LRA

Table 2.4-1, page 2.4-20 line item were included inadvertently. The cited GALL Report line item

(C-20) is for bellows for vent pipe downcomer parts of the primary containment pressure

boundary. The inner refueling bellows is not a containment pressure boundary component.

Failure of these bellows or the assembly will not prevent satisfactory accomplishment of a

safety function. Leakage, if any, through the bellows is directed to a drain system in the lower

drywell, and thus will stay in the drywell.

Based on its review, the staff finds the applicant's response to RAI 2.4.1-1 acceptable. The

staff's concern described in RAI 2.4.1-1 is resolved.

LRA Table 2.4-1 does not include drywell head closure bolts and double-gasketed drywell

heads. These components have the intended function of the drywell pressure boundary. In

RAI 2.4.1-2 dated November 29, 2006, the staff requested justification for their exclusion from

the scope of license renewal.

In its response dated December 28, 2006, the applicant stated that the drywell head closure

bolts are included in item ASME Classes 1, 2, 3 and MC supports bolting in LRA Table 2.4-4.

The drywell head gasket is within the scope of license renewal but replaced every time the head

is removed on a specified frequency and, therefore, not subject to an AMR.

Based on its review, the staff found the applicant's response unacceptable and requested a

clear description of the bolts in Table 2.4-4 because they have the important function to

maintain the drywell pressure boundary.

In a supplemental response dated April 24, 2007, the applicant included the drywell head

closure bolts in LRA Table 2.4-1, revised the LRA Table 2.4-1, page 2.4-19, item, "Drywell head

manway cover," to read "Drywell head manway cover and drywell head closure bolts," and

revised the LRA Table 3.5.2-1, page 3.5-56 item, "Drywell head manway cover," to read

"Drywell head manway cover and drywell head closure bolts."

Based on its review, the staff finds the applicant's response to RAI 2.4.1-2 acceptable. The

staff's concern described in RAI 2.4.1-2 is resolved.

In RAI 2.4.1-3 dated November 29, 2006, the staff stated that LRA Table 2.4-1 does not show

refueling cavity seal components within the scope of license renewal. Proposed license renewal

interim staff guidance LR-ISG-2006-01, "Plant Specific Aging Management Program for

inaccessible Areas of Boiling Water Reactor Mark 1 Steel Containment Drywell Shell," .

published in the Federal Register on May 9, 2006, states that the most likely cause of corrosion

of the drywell shell in the sand-pocket areas (near the bottom of the drywell) and in the

spherical portion of the drywell at higher elevations is water in the gap between the drywell and

the concrete shield. The water source was leakage through the seal between the drywell and

the refueling cavity and through the cracked stainless steel liner of the refueling cavity wall.

Therefore, the staff asked the applicant to include all the refueling cavity seal components

within the scope of license renewal and to provide a drawing that depicts the refueling cavity

seal components.

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In its response dated December 28, 2006, the applicant stated that the proposed license

renewal interim staff guidance LR-ISG-2006-01 states that, if moisture is detected or suspected

in the inaccessible area on the exterior of the drywell shell, any component source of moisture

(e.g., the refueling seal) should be included within the scope of license renewal subject to an

AMR. There has been no detected leakage causing moisture in the vicinity of the sand cushion

and none has been detected or suspected on the inaccessible areas of the drywell shell.

Therefore, consistent with the interim staff guidance, the refueling seal is not subject to an

AMR.

The applicant's letter attached drawings depicting the refueling cavity seal components.

By letter dated April 2, 2007, the staff requested the applicant's response to the following

specific questions:

(1) Is the refueling drain/seal pipe obstruction-free?

(2) What maintenance activities or administrative procedures are in place for the drain in

the trough area?

(3) What is the condition of the stainless steel liner of the refueling cavity walls ?

In its response dated April 24, 2007, the applicant stated that the outer refueling bellows drains

prevent refueling cavity leakage from entering the annulus air gap above the sand cushion. The

outer refueling bellows drain lines were inspected prior to start-up from the 1988 refuel outage.

Five of the six refueling bellows leakage drain lines inspected through inspection ports were

found to contain minor accumulation of debris including pieces of weld rod, indicating that it had

been introduced during construction. The amount of debris did not affect the ability of the drain

lines to perform their function. The applicant vacuumed and reinspected the lines and

determined them to be clear and functional as designed. An inspection port could not be

installed in the sixth line because of the piping configuration and the limited space available for

access.

The applicant explained that the bellows assembly seals the trough area where the drain lines

originate, preventing ingress of debris that could obstruct the lines. The only access to the area

for the 1988 inspections was through the drain lines with a boroscope. This design and the

redundancy in the number of drain lines make periodic inspections for whether the refueling

bellows drain piping is free of obstructions unwarranted. Leakage through the outer refueling

bellows, if any, flows into a common drain line with a flow indicator/switch that signals alarm in

the control room in any event of bellows leakage. A functional test of the flow switch 19FIS-62

prior to every refueling outage (two-year frequency) verifies indicator/switch and control room

annunciator functions. The applicant stated that there have been no failures of this test.

The applicant also stated that there has been no indication of refueling cavity steel liner

leakage, which would enter the trough area below the refueling bellows assembly and from

there flow into the drain system equipped with the flow alarm. There has been no actuation of

the flow alarm during refueling outages.

The applicant explained that leakage exceeding the capacity of the six drain lines (four 4-inch

drain lines and two 2-inch drain lines) would enter the annulus air gap and be detected flowing

from three of the four annulus air gap drains in the torus room. The applicant examined the air

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gaps through the drain lines using fiber optic cables in 1988 and recently in April 2007 and has

detected to date no evidence of moisture that could corrode the drywell shell. In the future, if it

detects any evidence of moisture, the applicant will determine additional inspection activities as

appropriate. Although no formal inspection or maintenance procedure is required for the

refueling cavity liner, routine observation during refueling operations and monitoring of the

refueling bellows drain system and alarm have detected no liner leakage.

Based on its review, the staff finds the applicant's response to RAI 2.4.1-3 acceptable because

there have been no problems with the (1) refueling drain/seal, (2) refueling bellows, or (3)

refueling pool liner. Moreover, the flow indicator switch alerts the applicant of any drain

malfunction. The staff's concern described in RAI 2.4.1-3 is resolved.

In RAI 2.4.1-4 dated November 29, 2006, the staff stated that LRA Table 2.4-1 does not include

the metal drywell sump screens that functionally support safety-related equipment. The staff

requested justification for their exclusion from the scope of license renewal.

In its response dated December 28, 2006, as supplemented April 24, 2007, the applicant

provided additional information and stated that the drywell sumps have no screens.

Based on the staff's review, the staff finds the applicant's response acceptable. The staff's

concern described in RAI 2.4.1-4 is resolved.

In RAI 2.4.1-5 dated November 29, 2006, the staff stated that LRA Table 2.4-1 does not include

the reinforced concrete shield plugs that shield the top of the drywell. Exclusion of the

reinforced concrete shield plugs from the scope of license renewal may lead to long-term

unmanaged degradation of the plugs (e.g., full sectional concrete cracking, rebar corrosion,

loss of bond, partial spalling or cracking of concrete due to handling, loss of load-carrying

capacity of plug attachments) with a seismic Il/I implication potentially affecting the structural,

integrity of the drywell head. The staff requested justification for their exclusion from the scope

of license renewal.

In its response dated December 28, 2006, the applicant stated that the reinforced shield plugs

that shield the top of the drywell are in LRA Table 2.4-4, "Bulk Commodities," under the line

item "Manways, hatches, and hatch covers."

The applicant's response was not acceptable to the staff. In a letter dated April 2, 2007, the

staff asked the applicant to list reinforced shield plugs separately from manways and hatches in

LRA Table 2.4-4.

In its response dated April 24, 2007, the applicant added concrete shield plugs as a separate

line item on LRA Table 2.4-1 under the component "concrete."

Accordingly, LRA Table 3.5.2-1 was revised to add the new line item with the material grouping ''concrete."

Based on its review, the staff finds the applicant's response to RAI 2.4.1-5 acceptable. The

staff's concern described in RAI 2.4.1-5 is resolved.

In RAI 2.4.1-6 dated November 29, 2006, the staff stated that LRA Table 2.4-1 does not show

spent fuel rack neutron-absorbing material within the scope of license renewal. Long-term

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unmanaged degradation of the component may reduce the margin of nuclear sub-criticality in

the fuel pool excessively. The staff requested justification for this exclusion from the scope of

license renewal.

In its response dated December 28, 2006, the applicant stated that the spent fuel rack

neutron-absorbing material is within the scope of license renewal, addressed in LRA

Section 2.3.3.9, and listed in LRA Table 2.3.3-9 with AMR results in LRA Table 3.3.2-9.

Based on its review, the staff finds the applicant's response to RAI 2.4.1-6 acceptable. The

staff's concern described in RAI 2.4.1-6 is resolved.

2.4.1.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the reactor building and primary containment components within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.4.2 Water Control Structures

2.4.2.1 Summary of Technical Information in the Application

LRA Section 2.4.2 describes the water control structures, which include the intake structure, the

intake tunnel, the screenwell-pumphouse structure, and the discharge tunnel. The intake

structure protects the inlet of the circulating water intake tunnel for a clear flow path for cooling

water into the tunnel. The reinforced concrete intake structure sits on the lake bottom

approximately 900 feet from the shoreline. Post-tensioned tendons anchor the main structure to

the natural bedrock below the lake bottom. A fan-shaped intake constructed of precast concrete

sections on the shoreward side of the main structure is anchored to the bedrock with grouted

rock bolts. Bar racks at the intake area prevent entrance of large debris. The circulating water

intake tunnel is the flow path for cooling water from the intake structure to the

screenwell-pumphouse structure housing the condenser circulating water pumps, normal

service water pumps, emergency service water pumps, residual heat removal service water

pumps, fire protection system supply pumps, and water treatment tanks and equipment. The

circulating water discharge tunnel is the return flowpath of cooling water from the

screenwell-pumphouse to the lake. The failure of this SEISMIC Class II structure could impact

the proper operation of the emergency service water system.

The water control structures have safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related water control structure SSCs

potentially could prevent the satisfactory accomplishment of a safety-related function. In

addition, the water control structures perform functions that support fire protection.

LRA Table 2.4-2 identifies the following water control structure component types within the

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scope of license renewal and subject to an AMR:

* steel

* other metals

• concrete

The water control structure component intended functions within the scope of license renewal

include:

shelter or protection to safety-related equipment, including radiation shielding and pipe

whip restraint

* rated fire barrier to confine or retard a fire from spreading

* protective barrier for flood events

* heat sink during SBO or DBA

* missile barrier

* structural or functional support to nonsafety-related equipment the failure of which could

impact safety-related equipment

• structural or functional support for fire protection, EQ, PTS, ATWS, or SBO

* structural or functional support for safety-related equipment

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and UFSAR Sections 12.2.2, 12.3.6, and 12.3.7 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and 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 of LRA Section 2.4.2 found areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as follows.

In RAI 2.4.2-1 dated November 29, 2006, the staff noted that LRA Section 2.4-2 under

"Discharge Tunnel" states that "failure of this Class II structure could impact the proper

operation of the emergency service water system." The staff requested additional information

about the potential consequences of a screenwell-pumphouse (Class II structure) failure.

Specifically, the staff asked the applicant what appropriate measures it had taken to prevent failure of this structure with adverse effects on the proper operation of the emergency SW

system.

In its response dated December 28, 2006, the applicant stated that the AMR produced

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appropriate measures for managing the effects of aging to prevent failure of this structure with

adverse effects on the proper operation of the emergency SW system. SW discharge flow is

routed to the lake via the discharge tunnel. Failure of the discharge tunnel could restrict the

normal SW discharge to the lake. Aging management of the screenwell-pumphouse and the

discharge tunnel is part of the Structures Monitoring Program as specified in LRA Table 3.5.2-2.

Based on its review, the staff finds the applicant's response to RAI 2.4.2-1 acceptable because

it included in the Structural Monitoring Program aging management of the screenwell-pump

house and the discharge tunnel to prevent failure of these structures. The staff's concern

described in RAI 2.4.2-1 is resolved.

In RAI 2.4.2-2 dated November 29, 2006, the staff noted that LRA Table 2.4-2 does not include

intake structure anchors and post-tensioned tendons that anchor the main structure to the

natural bedrock below the lake bottom. The staff requested justification for the exclusion of

these components from the scope of license renewal and a summary of operating experience

with settlement of the intake structure.

In its response dated December 28, 2006, the applicant stated that the anchorage system for

the intake structure is by post-tensioned rock bolts within the scope of license renewal under

anchorages/embedments in LRA Section 2.4.4. The applicant also stated that operating

experience indicated no settlement of the intake structure or degradation of the rock anchor

system (Reference JAF-RPT-05-LRD05).

Based on its review, the staff finds the applicant's response to RAI 2.4.2-2 acceptable as the

post-tension bolts are in the AMP and that its operating experience indicated no intake structure

settlement or rock anchor system degradation. The staff's concern described in RAI 2.4.2-2 is

resolved.

In RAI 2.4.2-3 dated November 29, 2006, the staff stated that LRA Table 2.4-2 lists "Beams,

columns, floor slabs, and walls" as a component and "Exterior walls" as another. The staff

requested the applicant to clarify by listing all structural members under each component.

In its response dated December 28, 2006, the applicant stated that, "Beams, columns, floor

slabs and walls," are defined as substructure or superstructure concrete parts of the primary

structural support function of a building or structure (e.g., structural columns, support girders,

and beams) and "exterior walls" as walls that form the perimeter base of a structure with their

primary surface or both surfaces exposed to an outdoor or soil environment (i.e., exposed to

weather).

Based on its review, the staff finds the applicant's response to RAI 2.4.2-3 acceptable because

it adequately clarified the component groups. The staff's concern described in RAI 2.4.2-3 is

resolved.

2.4.2.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

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components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the water control structures components within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.3 Turbine Building Complex and Yard Structures

2.4.3.1 Summary of Technical Information in the Application

LRA Section 2.4.3 describes the turbine building complex and yard structures:

" administration and control room building " CST foundation and retaining wall

" electric bay

" EDG building

• main stack

" manholes and duct banks

" nitrogen building

" radioactive waste building

" security building

" SGT building

" transformer/switchyard support structures

" transmission tower and foundation

" turbine building including feedwater heater bay

The administration and control room building housing the offices and work areas of the plant

operating personnel is situated between the reactor building and turbine building. This structure

consists of the control room for operating all facilities of the plant, the relay room, cable

spreading room, battery rooms, and control and relay room HVAC room.

The CST foundation and retaining wall support and protect the CSTs and their equipment. The

two CSTs rest on reinforced concrete foundations. The lower half of each stainless steel tank is

below ground level for tornado and SEISMIC protection from collapse of the surrounding soil by

a circular, reinforced concrete retaining wall. A reinforced concrete shield wall borders the CST

area to the north, west, and south of the tanks, shielding and protecting personnel protection

from radiation.

The electric bay housing various motor-generator sets and both 4160 V and 600 V switchgear

is part of the turbine building. The east and west cable tunnels under the electric bays separate

routing for redundant electrical and control services. The electric bays and cable tunnels are

SEISMIC Class I reinforced concrete structures with a reinforced concrete roof supported on

structural steel framing. The roof and exterior walls protect the interior equipment from tornado

damage.

The diesel generator building housing four EDGs is a one-story reinforced concrete structure

with a concrete roof supported by steel. The four EDG foundations are of reinforced concrete

isolated from the remainder of the structure. Concrete or reinforced concrete block walls

separate each diesel generator unit from the adjacent unit. Building construction is to SEISMIC

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Class I and tornado protection design criteria. Each diesel generator unit has its own

independent fuel oil system consisting of a main fuel storage tank, a day tank, and pumps. The

main tanks are buried below the subgrade and anchored to the rock foundation.

The main stack is an unlined, free-standing, SEISMIC Class I reinforced concrete structure

founded on a reinforced concrete mat anchored to bedrock with grouted reinforcing rods. The

stack sits on a circular filter room of reinforced concrete that houses dilution fans, off-gas filters,

and monitoring equipment.

Manholes and duct banks for underground routing of cables and piping are structural

components of concrete or reinforced concrete construction.

The nitrogen building housing containment air dilution equipment including liquid nitrogen

storage tanks is at the south end of the reactor building with north and east side walls- and floor

constructed of reinforced concrete. The remaining walls are steel frame with metal siding. The

roof is constructed of metal decking, insulation, and built-up roofing.

The SEISMIC Class II radioactive waste building is located east of the water treating building

and houses the equipment to handle liquid and solid radioactive wastes from the reactor

building and turbine building equipment.

The security building houses the security generator credited as a source of backup power to the

security lighting system, including the perimeter fence lighting, which illuminates exterior access

and egress in a fire with loss of 115KV offsite power.

The SGT building is a poured-in-place reinforced concrete structure adjacent to the reactor

building southeast corner. All construction joints below grade have preformed water stops for

water-tightness and vertical joints above grade for airtightness. The roof is constructed of

reinforced concrete.

The transformer/switchyard support structures physically support the reserve service

transformers T2 or T3 and the other switchyard components in the SBO recovery path. These

support structures include the transformer foundations, transformer pothead foundations and

support steel, and foundations for the switchyard breakers.

The transmission towers physically support the transmission lines in the SBO recovery path.

The transmission tower structures are the tower foundations and tower steel. The SEISMIC

Class II transmission tower is of galvanized steel construction on a reinforced concrete

foundation.

The turbine building and heater bay house the main turbine generator, condensate/feedwater

system, and other plant auxiliary systems. The building is a reinforced concrete structure with

concrete floors supported by structural steel. The superstructure housing the turbine building

crane is a structural steel frame covered with insulated metal siding and a metal roof deck with

insulation and built-up roofing. The interior walls of the turbine building are reinforced concrete

or concrete block designed to shield plant personnel and equipment from radiation and protect

them from fire. The SEISMIC Class II heater bay housing the feedwater heaters as part of the

turbine building is constructed of reinforced concrete below ground level with concrete and

grating floors supported by structural steel. The superstructure of one exterior wall and roof has

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a structural steel frame. The exposed wall is insulated metal siding and the roof is of metal deck

construction with insulation and built-up roofing except directly over the heaters where it is of

reinforced concrete for radiation protection.

The turbine building complex and yard structures have safety-related components relied upon

to remain functional during and following DBEs. The failure of nonsafety-related turbine building

complex and yard structure SSCs potentially could prevent the satisfactory accomplishment of

a safety-related function. In addition, the turbine building complex and yard structures perform

functions that support fire protection and SBO.

LRA Table 2.4-3 identifies the following turbine building complex and yard structure component

types within the scope of license renewal and subject to an AMR:

* steel

" other metals

" concrete

The turbine building complex and yard structure component intended functions within the scope

of license renewal include:

shelter or protection to safety-related equipment, including radiation shielding and pipe

whip restraint

* rated fire barrier to confine or retard a fire from spreading

* missile barrier

* pressure boundary

* structural or functional support to nonsafety-related equipment the failure of which could

impact safety-related equipment

* structural or functional support for fire protection, EQ, PTS, ATWS, or SBO

* structural or functional support for safety-related equipment

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and UFSAR Sections 5.2.3.8.6, 8.4, 8.5, 10.9.3, 12.2.2,

12.3.1, 12.3.2, 12.3.3, 12.3.4, 12.3.5, 12.3.9, and 12.3.12, and 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

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 of LRA Section 2.4.3 found areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as follows.

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In RAI 2.4.3-1 dated November 29, 2006, the staff noted that UFSAR Section 12.3.9 states,

"The stack is not specifically designed to resist a tornado." The staff needed additional

information about the potential interaction between seismic Class II SSCs and tornado-induced

failure of the main stack. Specifically, the staff asked the applicant what appropriate measures it

had taken to prevent interactions between the main stack and nearby seismic Class I and

Class II SSCs the failure of which might have adverse effects on seismic Class I SSCs.

In its response dated December 28, 2006, the applicant confirmed that a tornado-induced

failure of the main stack would not interact with nearby seismic Class II SSCs the failure of

which might cause loss of seismic Class I SSC intended functions. As stated in LRA

Section 2.4.3, the main stack is a seismic Class I reinforced concrete structure located

sufficiently far from other seismic Class I structures to preclude interaction, including that

caused by interaction with nearby seismic Class II SSCs the failure of which might have

adverse effects on seismic Class I SSCs.

By letter dated April 2, 2007, the staff requested the applicant to demonstrate with a sketch

showing the distance from the stack to seismic Classes I and II structures with potential

tornado-induced interaction that the main stack is sufficiently far from seismic class I structures.

In its response dated April 24, 2007, the applicant stated that the main stack is designed as a

seismic Class I structure but not for tornado loads. The nearest seismic Class I or II structure to

the stack is the SGT room at a distance slightly less than the "topple" zone of the main stack.

Site drawings FY-12B and FY-12D (attached to the response) show the main stack and reactor

track bay (which contains the SGT room). Calculation JAF-CALC-BYM-04122 confirmed a

crushing and "breaking" main stack failure mode at a location above the base. The calculation

conclusion states that interaction of a main stack failure with the SGT room is unlikely. For

license renewal, the main stack is within the scope of license renewal and subject to an AMR.

the Structures Monitoring Program manages the effects of aging on the main stack.

Based on its review, the staff finds the applicant's response to RAI 2.4.3-1 acceptable because,

after examining the locations of the nearby structures and components, the applicant concluded

that interaction of a main stack failure with seismic Class I or II structures is unlikely. The staff

agrees with the applicant's conclusion. The staff's concern described in RAI 2.4.3-1 is resolved.

In RAI 2.4.3-2 dated November 29, 2006, the staff noted that LRA Section 2.4-3 states that,

"The main steam lines to the turbine generator from the reactor are housed in a reinforced

concrete tunnel that enters the turbine building after passing under the adjacent administration

building." The staff needed additional information about the potential interaction between the

administration building and any failure of main steam lines. Specifically, the staff asked the

applicant what appropriate measures it had taken to prevent failure of the MS lines with adverse

effect on the administration building.

In its response dated December 28, 2006, the applicant stated that LRA Section 2.3.4.2

addresses and LRA Table 3.3.2-14-16 lists the MS lines. Appropriate measures (AMPs) are in

place to manage the effects of aging and to prevent MS line failure and the potential effect on

the administration building.

Based on its review, the staff finds the applicant's response to RAI 2.4.3-2 acceptable. The

staff's concern described in RAI 2.4.3-2 is resolved.

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In RAI 2.4.3-3 dated November 29, 2006, the staff noted that LRA Table 2.4-3 lists "Exterior

walls" as a component. The staff could not determine whether this component included the

main stack, MS line tunnel, and electric bay tunnel. The staff asked the applicant to include

these components within the scope of license renewal.

In its response dated December 28, 2006, the applicant stated that exterior walls are defined as

walls that form the perimeter base of a structure with their primary surface or both surfaces

exposed to an outdoor or soil environment (i.e., exposed to weather). This definition would

include the exterior walls of those structures listed.

Based on its review, the staff finds the applicant's response to RAI 2.4.3-3 acceptable. The

staff's concern described in RAI 2.4.3-3 is resolved.

In RAI 2.4.3-4 dated November 29, 2006, the staff noted that LRA Table 2.4-3 does not include

sumps that functionally support safety-related and nonsafety-related equipment. The staff

requested justification for their exclusion from the scope of license renewal.

In its response dated December 28, 2006, the applicant stated that the in-scope unlined sumps

in the east cable tunnel are parts of the concrete floor structure. There are no other sumps in

the turbine building complex and yard structures that functionally support safety-related and

nonsafety-related equipment. LRA Section 2.3.3.12 addresses turbine building equipment drain

tanks within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.4.3-4 acceptable. The

staffs concern described in RAI 2.4.3-4 is resolved.

2.4.3.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff s review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the turbine building complex and yard structures components within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.4.4 Bulk Commodities

2.4.4.1 Summary of Technical Information in the Application

LRA Section 2.4.4 describes the bulk commodities, which are structural components or

commodities that perform or support intended functions of in-scope SSCs.

Bulk commodities have safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related bulk commodity SSCs potentially could prevent

the satisfactory accomplishment of a safety-related function. In addition, the bulk commodities

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perform functions that support fire protection.

LRA Table 2.4-4 identifies the following bulk commodity component types within the scope of

license renewal and subject to an AMR:

* steel and other metals

* bolted connections

* concrete

* other materials

The bulk commodities component intended functions within the scope of license renewal

include:

" shelter or protection to safety-related equipment, including radiation shielding and pipe

whip restraint

" rated fire barrier to confine or retard a fire from spreading

" protective barrier for flood events

" insulation

* missile barrier

* pressure boundary

* structural or functional support to nonsafety-related equipment whose failure could

impact safety-related equipment

" structural or functional support for fire protection, EQ, PTS, ATWS, or SBO

• structural or functional support for safety-related equipment

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, 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

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed

those components that the applicant has identified as within the scope of license renewal to

verify that the applicant has not omitted any passive and long-lived components subject to an

AMR in accordance with the requirements of 10 CFR 54.21(a)(1).

In RAI 2.4.4-1 dated November 29, 2006, the staff noted that LRA Table 2.4-4 lists bulk

commodities. The location of each component was unclear to the staff. The staff requested a

description of all listed commodities as well as a comprehensive listing of components,

component supports, and locations for each commodity.

In its response dated December 28, 2006, the applicant explained that, as stated in LRA

Section 2.4.4, LRA Table 2.4-4 lists the bulk commodities common to in-scope structures.

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Commodities unique to any specific structure are included in the review for that structure (LRA

Sections 2.4.1 through 2.4.3). The commodities listed in LRA Table 2.4-4 are within the scope

of license renewal and subject to an AMR regardless of the in-scope structure in which located.

Components classified as bulk commodities typically have no unique component identification

numbers. Therefore, a comprehensive listing of components and locations is not feasible.

Based on its review, the staff finds the applicant's response to RAI 2.4.4-1 acceptable because

the staff agrees with the applicant's reasons for not listing bulk commodities. The staff's

concern described in RAI 2.4.4-1 is resolved.

In RAI 2.4.4-2 dated November 29, 2006, the staff noted that LRA Table 2.4-4 lists "insulation"

with intended functions. It was unclear to the staff why "Support for Criterion (a)(1) equipment"

was not an intended function when the LRA Table 2.0-1 definition of the intended function of

"insulation" meant to apply to safety-related and nonsafety-related components is "provide

insulating characteristics to reduce heat transfer." The staff requested additional information on

insulation and a list of in-scope components with insulation included with their intended

functions.

In its response dated December 28, 2006, the applicant stated that LRA Table 2.4-4 lists two

functions for insulation. LRA Table 2.0-1 defines the first, "Insulation," as, "Provide insulating

characteristics to reduce heat transfer." This function applies to safety-related and

nonsafety-related components. LRA Table 2.0-1 defines the second function, "Support for

Criterion (a)(2) equipment," as, "Provide structural or functional support to nonsafety-related

equipment whose failure could impact safety-related equipment." This definition means

nonsafety-related insulation must maintain integrity so falling insulation does not damage

safety-related equipment. Therefore, "Support for Criterion (a)(1) equipment" need not be listed

as a separate intended function for insulation.

The applicant also stated that examples of in-scope components with insulation addressed by

this LRA Table 2.4-4 line item are the recirculation system piping, valves, and pump casings

and MS SRVs. The applicant evaluated insulation as a commodity because development of a

list of individual components insulated was not practical. Therefore, a list of insulated

components is not available.

Based on its review, the staff finds the applicant's response to RAI 2.4.4-2 acceptable because

it explained the intended functions of the insulation and clarified component insulation included

within the scope of the license renewal. The staff's concern described in RAI 2.4.4-2 is

resolved.

In RAI 2.4.4-3 dated November 29, 2006, the staff stated that LRA Section 2.4.4 includes

review of bulk commodities such as structural components or commodities that support

intended functions of in-scope SSCs. It is not clear from the review of LRA Tables 2.4-4, "Bulk

Commodities Summary of Components Subject to Aging Management Review," and 3.5.2-4,

"Bulk Commodities Summary of Aging Management Evaluation," that the structural fire barriers

(walls, ceilings, floors, and slabs) are within the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If these

structural fire barriers are excluded from the scope of license renewal and not subject to an

AMR, the staff requested that the applicant provide justification for the exclusion.

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In its response dated December 28, 2007, the applicant stated that the structural fire barriers

(walls, ceilings, floors and slabs) are within the scope of license renewal and subject to an

AMR. They are listed within the tables of the associated structures with an intended function

"FB." The AMP for these commodities is the Fire Protection Program.

Based on its review, the staff finds the applicant's response to RAI 2.4.4-3 acceptable because

structural fire barriers in question were identified to be within the scope of license renewal and

subject to an AMR. The applicant stated that the structural fire barriers, i.e., walls, ceilings,

floors and slabs are represented in the LRA tables of the associated structures with an intended

function "FB." Therefore, the staff concludes that the structural fire barriers are correctly

included within the scope of license renewal and subject to an AMR. The staff's concern

described in RAI 2.4.4-1 is resolved.

2.4.4.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the bulk commodities components within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control Systems

This section documents the staffs review of the applicant's scoping and screening results for

electrical and instrumentation and controls (I&C) 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

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 component

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

electrical and I&C system to determine whether the applicant has omitted from the scope of

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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) if the functions are

performed with moving parts or a change in configuration or properties or (2) the SCs are

subject to replacement after a qualified life or specified time period, as described in

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that

these SCs were subject to an AMR, as required by 10 CFR 54.21 (a)(1). The staff requested

additional information to resolve any omissions or discrepancies identified.

2.5.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes the electrical and I&C systems, which are included within the

scope of license renewal as are electrical and I&C components in mechanical systems. The

default inclusion of plant electrical and I&C systems within the scope of license renewal reflects

the method for the IPAs of electrical systems. This method is different from those for IPAs of

mechanical systems and structures.

The basic philosophy of the electrical and I&C components IPA is to include components not

specifically screened out. When used with the plant spaces approach, this method eliminates

the need for unique identification of every component and its specific location so components

are not improperly excluded from AMR. The electrical and I&C IPA begins with commodity

groups of similar electrical and I&C components with common characteristics and component

intended functions of the groups. The IPA eliminates commodity groups and specific plant

systems from further review as it examines intended functions of commodity groups. In addition

to the plant electrical systems the IPA conservatively includes within the scope of license

renewal certain switchyard components required to restore offsite power following an SBO.

The electrical and I&C system performs functions that support SBO.

LRA Table 2.5-1 identifies the following electrical and I&C system component types within the

scope of license renewal and subject to an AMR:

* 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

* fuse holders (insulation material)

" high-voltage insulators (for SBO)

" metal-enclosed bus (non-segregated bus for SBO), connections

" metal-enclosed bus (non-segregated bus for SBO), insulation/insulators

. metal-enclosed bus (non-segregated bus for SBO) enclosure assemblies

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• oil-filled cable system (passive mechanical for SBO)

" oil-filled cable system (passive electrical for SBO)

" switchyard bus (switchyard bus for SBO), connections

• transmission conductors (transmission conductors for SBO), connections

The electrical and I&C system component intended functions within the scope of license

renewal include:

• electrical connections for voltage, current, or signals * insulation and support for electrical conductors

* pressure boundary

• structural or functional support for fire protection, EQ, PTS, ATWS, or SBO

2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 and the UFSAR 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).

In RAI 2.5-1 dated January 12, 2007, the staff asked the applicant to clarify why the switchyard

bus was not shown in license renewal Figure 2.5-1 even though included in the list of

components/commodity groups subject to an AMR.

In its response dated February 12, 2007, the applicant stated that the switchyard bus within the

scope of license renewal and subject to an AMR consists of short sections that connect to the

115 kilo-volt (kV) underground oil-filled transmission cables at reserve station service

transformer (T2) and switchyard breaker (10022). Also included are the short sections that

connect to the overhead transmission conductors at reserve station service transformer (T3)

and switchyard breaker (10012). The applicant updated license renewal Figure 2.5-1.

Based on its review, the staff finds the applicant's response to RAI 2.5-1 acceptable. The staff's

concern described in RAI 2.5-1 is resolved.

2.5.3 Conclusion

The staff reviewed the LRA and UFSAR, and the supplemental information in the applicant's

letter dated February 12, 2007, to determine whether the applicant failed to identify any SSCs

within the scope of license renewal. The staff finds no such omissions. In addition, the staff's

review determined whether the applicant failed to identify any components subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

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reasonable assurance that the applicant has adequately identified the electrical and I&C system

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.6 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.

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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 James A. FitzPatrick Nuclear Power Plant

(JAFNPP), by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the

staff). In Appendix B of its license renewal application (LRA), Entergy Nuclear Operations, Inc.

(ENO or the applicant) described the 35 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-1 801, Revision 1, "Generic Aging Lessons

Learned (GALL) Report," dated September 2005. The GALL Report contains the staffs generic

evaluation of the existing plant programs and documents the technical basis for determining

where existing programs are adequate without modification, and where existing programs

should be augmented for the period of extended operation. The evaluation results documented

in the GALL Report indicate that many of the existing programs are adequate to manage the

aging effects for particular license renewal SCs. The GALL Report also contains

recommendations on specific areas for which existing programs should be augmented for

license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its

programs correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or

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

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced,

improving the efficiency and effectiveness of the license renewal review process. The GALL

Report also serves as a quick reference for applicants and staff reviewers to AMPs and

activities that the staff has determined will adequately manage or monitor aging during the

period of extended operation.

The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials,

(3) environments to which the SCs are exposed, (4) the aging effects of the materials and

environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6)

recommendations for further applicant evaluations of aging management for certain component

types.

To determine whether use of the GALL Report would improve the efficiency of LRA review, the

staff conducted a demonstration of the GALL Report process in order to model the format and

content of safety evaluations based on it. The results of the demonstration project confirmed

that the GALL Report process will improve the efficiency and effectiveness of LRA review while

maintaining the staffs focus on public health and safety. NUREG-1800, Revision 1, "Standard

3-1
Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

dated September 2005, was prepared based on both the GALL Report model and lessons

learned from the demonstration project.

The staff's review was in accordance with Title 10, Part 54, of the Code of Federal Regulations

(10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants,"

and the guidance of the SRP-LR and the GALL Report.

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and

associated AMPs during the weeks of November 13-17, 2006, December 11-15, 2006, and

January 8-9, 2007. The staff conducted its audits and reviews in accordance with the Audit Plan

(Agencywide Documents Access and Management System (ADAMS) Accession

No. ML0627801551). The onsite audits and reviews are designed for maximum efficiency and

effectiveness of the staff's LRA review. The applicant can respond to questions, the staff can

readily evaluate the applicant's responses, the need for formal correspondence between the

staff and the applicant is reduced, and the result is an improvement in review efficiency. The

audit questions are documented in an audit and review question and answer database that can

be viewed through ADAMS Accession No. ML070380231. In addition, the staff issued an audit

summary (ADAMS Accession No. ML071580047) of the audit and review results and an audit

team's evaluation of the applicant's responses to the audit questions (ADAMS Accession

No. ML080140466).

3.0.1 Format of the License Renewal Application

The applicant submitted an application that follows the standard LRA format agreed to by the

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003 (ML030990052). This

revised LRA format incorporates lessons learned from the staff's reviews of the previous five

LRAs, which used a format developed from information gained during a staff-NEI demonstration

project conducted to evaluate the use of the GALL Report in the LRA review process.

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents

AMR results information in the following two table types:

(1) Table ls: Table 3.x.1 -where "3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, and "1" indicates that this table type is the

first in LRA Section 3.

(2) Table 2s: Table 3.x.2-y - where "3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, "2" indicates that this table type is the second

in LRA Section 3, and "y" indicates the system table number.

The content of the previous LRAs and of the JAFNPP application is essentially the same. The

intent of the revised format of the LRA was to modify the tables in LRA Section 3 to provide

additional information that would assist in the staff's review. In its Table is, the applicant

summarized the portions of the application that it considered to be consistent with the GALL

Report. In its Table 2s, the applicant identified the linkage between the scoping and screening

results in LRA Section 2 and the AMRs in LRA Section 3.

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3.0.1.1 Overview of Table ls

Each Table 1 compares in summary how the facility aligns with the corresponding tables in the

GALL Report. The tables are essentially the same as Tables 1 through 6 in the GALL Report,

except that the "Type" column has been replaced by an "Item Number" column and the "Item

Number in GALL" column has been replaced by a "Discussion" column. The "Item Number"

column is a means for-the staff reviewer to cross-reference Table 2s with Table is. In the

"Discussion" column the applicant provided clarifying information. The following are examples of

information that might be contained within this column:

further evaluation recommended - information or reference to where that information is

located

° The name of a plant-specific program

° exceptions to GALL Report assumptions

* discussion of how the line is consistent with the corresponding line item in the GALL

Report when the consistency may not be obvious

discussion of how the item is different from the corresponding line item in the GALL

Report (e.g., when an exception is taken to a GALL AMP)

The format of each Table 1 allows the staff to align a specific row in the table with the

corresponding GALL Report table row so that the consistency can be checked easily.

3.0.1.2 Overview of Table 2s

Each Table 2 provides the detailed results of the AMRs for components identified in LRA

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures

within a specific system grouping (e.g., reactor coolant system, engineered safety features,

auxiliary systems, etc.). For example, the engineered safety features group has tables specific

to the core spray system, high pressure coolant injection system, and residual heat removal

system. Each Table 2 consists of nine columns:

(1) Component Type - The first column lists LRA Section 2 component types subject to an

AMR in alphabetical order.

(2) Intended Function - The second column identifies the license renewal intended

functions, including abbreviations where applicable, for the listed component types.

Definitions and abbreviations of intended functions are in LRA Table 2.0-1.

(3) Material - The third column lists the particular construction material(s) for the

component type.

(4) Environment - The fourth column lists the environments to which the component types

are exposed. Internal and external service environments are indicated with a list of these

environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3.

(5) Aging Effect Requiring Management - The fifth column lists aging effects requiring

management (AERMs). As part of the AMR process, the applicant determined any

AERMs for each combination of material and environment.

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(6) Aging Management Programs - The sixth column lists the AMPs that the applicant uses

to manage the identified aging effects.

(7) NUREG-1 801 Volume 2 Item - The seventh column lists the GALL Report item(s)

identified in the LRA as similar to the AMR results. The applicant compares each

combination of component type, material, environment, AERM, and AMP in LRA

Table 2 with the GALL Report items. If there are no corresponding items in the GALL

Report, the applicant leaves the column blank in order to identify the AMR results in the

LRA tables corresponding to the items in the GALL Report tables.

(8) Table 1 Item - The eighth column lists the corresponding summary item number from

LRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with

the GALL Report the Table 1 line item summary number should be listed in LRA

Table 2. If there is no corresponding item in the GALL Report, column eight is left blank.

In this manner, the information from the two tables can be correlated.

(9) Notes - The ninth column lists the corresponding notes used to identify how the

information in each Table 2 aligns with the information in the GALL Report. The notes,

identified by letters, were developed by an NEI work group and will be used in future

LRAs. Any plant-specific notes identified by numbers provide additional information

about the consistency of the line item with the GALL Report.

3.0.2 Staff's Review Process

The staff conducted three types of evaluations of the AMRs and AMPs:

(1) For items that the applicant stated were consistent with the GALL Report the staff

conducted either an audit or a technical review to determine such consistency.

(2) For items that the applicant stated were consistent with the GALL Report with

exceptions, enhancements, or both, the staff conducted either an audit or a technical

review of the item to determine such consistency. In addition, the staff conducted either

an audit or a technical review of the applicant's technical justifications for the exceptions

or the adequacy of the enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific GALL

AMP elements; however, any deviation from or exception to the GALL AMP should be

described and justified. Therefore, the staff considers exceptions as being portions of

the GALL AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet

all the program elements defined in the GALL AMP. However, the applicant may make a

commitment to augment the existing program to satisfy the GALL AMP prior to the

period of extended operation. Therefore, the staff considers these augmentations or

additions to be enhancements. Enhancements include, but are not limited to, activities

needed to ensure consistency with the GALL Report recommendations. Enhancements

may expand, but not reduce, the scope of an AMP.

(3) For other items, the staff conducted a technical review to verify conformance with

10 CFR 54.21(a)(3) requirements.

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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 AMPs, the staff conducted

either an audit or a technical review to verify the claim. For each AMP with one or more

deviations, the staff evaluated each deviation to determine whether the deviation was

acceptable and whether the modified AMP would adequately manage the aging effect(s) for

which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full

review-to determine their adequacy. The staff evaluated the AMPs against the following

10 program elements defined in SRP-LR Appendix A.

(1) Scope of the Program - Scope of the program should include the specific SCs subject

to an AMR for license renewal.

(2) Preventive Actions - Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected - Parameters monitored or inspected should be

linked to the degradation of the particular structure or component intended function(s).

(4) Detection of Aging Effects - Detection of aging effects should occur before there is a

loss of structure or component intended function(s). This includes aspects such as

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample

size, data collection, and timing of new/one-time inspections to ensure timely detection

of aging effects.

(5) Monitoring and Trending - Monitoring and trending should provide predictability of the

extent of degradation as well as timely corrective or mitigative actions.

(6) Acceptance Criteria - Acceptance criteria, against which the need for corrective action

will be evaluated, should ensure that the structure or component intended function(s)

are maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process - Confirmation process should ensure that preventive actions are

adequate and that appropriate corrective actions have been completed and are

effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and

approval process.

(10) Operating Experience - Operating experience of the AMP, including past corrective

actions resulting in program enhancements or additional programs, should provide

objective evidence to support the conclusion that the effects of aging will be adequately

managed so that the SC intended function(s) will be maintained during the period of

extended operation.

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Details of the staff's audit evaluation of program elements (1) through (6) are documented in

the Audit Summary report dated June 19, 2007 (ADAMS Accession No. ML071580047), and

are summarized 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.

3.0.2.2 Review of AMR Results

Each LRA Table 2 contains information concerning whether or not the AMRs identified by the

applicant algin with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed

the intended function, material, environment, AERM, and AMP combination for a particular - -system component type. Item numbers in column seven of the LRA, "GALL Report Volume 2

Item," correlates to an AMR combination as identified in the GALL Report. The staff also

conducted onsite audits to verify these correlations. A blank in column seven indicates that the

applicant was unable to identify an appropriate correlation in the GALL Report. The staff also

conducted a technical review of combinations not consistent with the GALL Report. The next

column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.

3.0.2.3 UFSAR Supplement

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed

the UFSAR supplement, which summarizes the applicant's programs and activities for

managing the effects of aging for the period of extended operation, as required by

10 CFR 54.21(d).

3.0.2.4 Documentation and Documents Reviewed

In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.

During the onsite audit, the staff also examined the applicant's justifications to verify that the

applicant's activities and programs will adequately manage the effects of aging on SCs. The

staff also conducted detailed discussions and interviews with the applicant's license renewal

project personnel and others with technical expertise relevant to aging management.

The staff noted that the LRA did not include a complete "Commitment List," and descriptions of

some proposed new AMPs and AMP "enhancements" in LRA Appendix A are incomplete.

The staff's review of LRA Appendix A found an area in which additional information was

necessary to complete the review of the applicant's regulatory commitments. The applicant

responded to the staff's request for additional information (RAI).

In RAI Appendix A-1 dated November 7, 2006, the staff requested a commitment list showing

all regulatory commitments.

3-6
In its response dated December 6, 2006, the applicant submitted the commitment list, LRA,

Revision 0, Amendment 1, Attachment 1. After the staffs audit and review, the applicant

revised this commitment list in its letter dated February 1, 2007, LRA Amendment No. 5.

3.0.3 Aging Management Programs

SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA

Appendix B. The table also indicates the SCs that credit the AMPs and the GALL AMP with

which the applicant claimed consistency and shows the section of this SER in which the staff's

evaluation of the program is documented.

Table 3.0.3-1 JAFNPP Aging Management Programs

JAFNPP AMP GALL Report GALL Report LRA Systems or Structures Staff's

(LRA Section) Comparison AMPs That Credit the AMP SER Section

Existing AMPs

BWR CRD Return Line Consistent with XI.M6 reactor vessel, internals, and 3.0.3.2.2

Nozzle Program exceptions and reactor coolant system

(B.1.2) enhancement

BWR Feedwater Consistent with XI.M5 reactor vessel, internals, and 3.0.3.2.3

Nozzle Program exception reactor coolant system

(B.1.3)

BWR Penetrations Consistent with XI.M8 reactor vessel, internals, and 3.0.3.2.4

Program exception reactor coolant system

(B.1.4)

BWR Stress Corrosion Consistent with XI.M7 reactor vessel, internals, and 3.0.3.2.5

Cracking Program exception reactor coolant system

(B.1.5)

BWR Vessel ID Consistent with XI.M4 reactor vessel, internals, and 3.0.3.2.6

Attachment Welds exception reactor coolant system

Program

(B.1.6)

BWR Vessel Internals Consistent with XI.M9 reactor vessel, internals, and 3.0.3.2.7

Program exceptions reactor coolant system

(B.1.7)

Containment Leak Consistent XI.S4 structures and component 3.0.3.1.1

Rate Program supports

(B.1.8)

Diesel Fuel Monitoring. Consistent with XI.M30 auxiliary systems 3.0.3.2.8

Program exception and

(8.1.9) enhancements

Environmental Consistent X.E1 electrical and instrumentation 3.0.3.1.2

Qualification of Electric and controls

Components Program

(8.1.10)

3-7
JAFNPP AMP GALL Report GALL Report LRA Systems or Structures Staff's

(LRA Section) Comparison AMPs That Credit the AMP SER Section

External Surfaces Consistent with XI.M36 reactor vessel, internals, and 3.0.3.2.9

Monitoring Program enhancement reactor coolant system /

(B.1.11) engineered safety features

systems / auxiliary systems I

steam and power conversion

systems / electrical and

instrumentation and controls

Fatigue Monitoring Consistent with X.M1 reactor vessel, internals, and 3.0.3.2.10

Program exceptions reactor coolant system /

(B.1.12) engineered safety features

systems / auxiliary systems /

steam and power conversion

systems structures / and

component supports

Fire Protection Consistent with XI.M26 auxiliary systems / structures 3.0.3.2.11

Program enhancements and component supports

(B.1.13.1)

Fire Water System Consistent with XI.M27 auxiliary systems / structures 3.0.3.2.12

Program exceptions and and component supports

(B. 1.13.2) enhancements

Flow-Accelerated Consistent XI.M17 reactor vessel, internals, and 3.0.3.1.3

Corrosion Program reactor coolant system /

(3,1.14) engineered safety features

systems / auxiliary systems /

steam and power conversion

systems

Containment Inservice Plant-specific structures and component 3.0.3.3.2

Inspection Program supports

(1.1.16.1)

Inservice Inspection Plant-specific reactor vessel, internals, and 3.0.3.3.3

Program reactor coolant system /

(1, 1.16.2) structures and component

supports

Oil Analysis Program Consistent with XI.M39 engineered safety features 3.0.3.2.14

(B.1.20) exception and systems / auxiliary systems /

enhancements electrical and instrumentation

and controls

Periodic Surveillance Plant-specific engineered safety features 3.0.3.3.4

and Preventive systems / auxiliary systems I

Maintenance Program structures and component

(B.1.22) supports

Reactor Head Closure Consistent with XI.M3 reactor vessel, intemals, and 3.0.3.2.15

Studs Program exception reactor coolant system

(8.1.23)

Reactor Vessel Consistent with XI.M31 reactor vessel, internals, and 3.0.3.2.16

Surveillance Program enhancement reactor coolant system

(B.1.24)

3-8
JAFNPP AMP GALL Report GALL Report LRA Systems or Structures Staff's

(LRA Section) Comparison AMPs That Credit the AMP SER Section

Service Water Integrity Consistent with XI.M20 engineered safety features 3.0.3.2.17

Program exception systems / auxiliary systems

(B.1.26)

Masonry Wall Program Consistent XI.S5 structures and component 3.0.3.1.8

(B.1.27.1) supports

Structures Monitoring Consistent with XI.S6 structures and component 3.0.3.2.18

Program enhancements supports

(B.1.27.2)

Water Chemistry. Plant-specific auxiliary systems 3.0.3.3.5

Control - Auxiliary

Systems, Program

(B.1.29.1)

Water Chemistry Consistent XI.M2 reactor vessel, internals, and 3.0.3.1.10

Control - BWR reactor coolant system /

Program engineered safety features

(B.1.29.2) systems / auxiliary systems /

steam and power conversion

systems structures / and

component supports

Water Chemistry Consistent with XI.M21 reactor vessel, internals, and 3.0.3.2.19

Control - Closed exception reactor coolant system /

Cooling Water engineered safety features

Program systems / auxiliary systems

(B.1.29.3)

New AMPs

Buried Piping and Consistent with XI.M34 engineered safety features 3.0.3.2.1

Tanks Inspection exception systems i auxiliary systems /

Program steamand power conversion

(B.1.1) systems

Heat Exchanger Plant-specific engineered safety features 3.0.3.3.1

Monitoring Program systems / auxiliary systems

(B.1.15)

Metal-Enclosed Bus Consistent with XI.E4 electrical and instrumentation 3.0.3.2.13

Inspection Program exception and controls

(B.1.17)

Non-EQ Consistent XI.E2 electrical and instrumentation 3.0.3.1.4

Instrumentation and controls

Circuits Test Review

Program

(B.1.18)

Non-EQ Insulated Consistent XI.E1 electrical and instrumentation 3.0.3.1.5

Cables and and controls

Connections Program

(B.1.19)

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JAFNPP AMP GALL Report GALL Report LRA Systems or Structures Staffs

(LRA Section) Comparison AMPs That Credit the AMP SER Section

One-Time Inspection Consistent XI.M32 engineered safety features 3.0.3.1.6

Program XI.M35 systems / auxiliary systems

(B.1.21)

Selective Leaching Consistent XI.M33 engineered safety features 3.0.3.1.7

Program systems / auxiliary systems

(B.1.25)

Thermal Aging and Consistent XI.M13 reactor vessel, internals, and 3.0.3.1.9

Neutron Irradiation reactor coolant system

Embrittlement of Cast

Austenitic Stainless

Steel Program

(B.1.28)

Bolting Integrity Consistent with XI.M18 reactor vessel, internals, and 3.0.3.2.20

Program enhancements reactor coolant system /

(B.1.30) engineered safety features

systems / auxiliary systems /

steam and power conversion

systems

Bolted Connection Plant-specific electrical and instrumentation 3.0.3.3.6

Program (B.1.31) I and controls

3.0.3.1 AMPs Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL

Report:

* Containment Leak Rate Program

0 Environmental Qualification of Electric Components Program

0 Flow-Accelerated Corrosion Program

0 Non-EQ Instrumentation Circuits Test Review Program

0 Non-EQ Insulated Cables and Connections Program

0 One-Time Inspection Program

a Selective Leaching Program

* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

Program

9 Water Chemistry Control - BWR Program

3.0.3.1.1 Containment Leak Rate Program

Summary of Technical Information in the Application. LRA Section B. 1.8 describes the existing

Containment Leak Rate Program as consistent with GALL AMP XI.S4, "10 CFR 50,

Appendix J."

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Containment leak rate tests are required for assurance that (a) leakage through primary reactor

containment and systems and components penetrating the primary containment does not

exceed allowable technical specifications or their bases and (b) there is periodic surveillance of

reactor containment penetrations and isolation valves so that proper maintenance and repairs

are made during the service life of the containment and systems and components penetrating

the primary containment.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Containment Leak

Rate Program bases documents. Specifically,. the staff reviewed the program elements and

corresponding bases documents for consistency with GALL AMP XI.S4. The staff noted that the

applicant chose 10 CFR- Part 50, Appendix J, Option B (performance-based approach) for

implementing this program. The containment leak rate tests are in accordance with the

guidance of Regulatory Guide (RG) 1.163 and NEI 94-01. The staff finds the applicant's

Containment Leak Rate Program acceptable consistent with GALL AMP XI.S4, including the

operating experience attribute, and acceptable.

Operatinq Experience. LRA Section B. 1.8 states that during the most recent integrated leakage

testing of the primary containment as-found and as-left test data met all applicable test

acceptance criteria with no degradation threatening the structural integrity of the containment,

indicating the program's effective management of the effects of loss of material and cracking on

primary containment components. A QA audit in March 2002 and self-assessments in 2004 and

2005 revealed no issues or findings with impact on program effectiveness. As stated in GALL

Report Section XI.S4, "To date, the 10 CFR Part 50, Appendix J, LRT program has been

effective in preventing unacceptable leakage through the containment pressure boundary.

Implementation of Option B for testing frequency must be consistent with plant-specific

operating experience." The program is consistent with the GALL Report and 10 CFR Part 50,

Appendix J requirements and, therefore, effective at managing loss of material and cracking.on

primary containment components.

The staff reviewed the operating experience in the LRA and operating experience reports and

also interviewed the applicant's technical personnel and confirmed that plant-specific operating

experience shows no aging effects for systems and components within the scope of this

program not bounded by industry operating experience. The staff noted there were no

aging-related condition reports (CRs) of degradation that would threaten the structural integrity

of the containment. The staff finds this fact an acceptable indication that components have

experienced no aging effects not bounded by industry operating experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.8, the applicant provided the UFSAR supplement for

the Containment Leak Rate Program. The staff determined that the information in the UFSAR

supplement provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

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Conclusion. On the basis of its audit and review of the applicant's Containment Leak Rate

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.2 Environmental Qualification of Electric Components Program

Summary of Technical Information in the Application. LRA Section B.1.10 describes the existing

Environmental Qualification of Electric Components Program as consistent with GALL

AMP X.E1, "Environmental Qualification (EQ) of Electric Components."

The NRC specifically requires EQ programs to demonstrate that certain electrical components

are qualified to perform their safety function in harsh plant environments. Under 10 CFR 50.49

the effects of significant aging mechanisms must be addressed as part of EQ. The EQ of

Electric Components Program manages the effects of thermal, radiation, and cyclic aging

through aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by

10 CFR 50.49, EQ components are refurbished or replaced or their qualification is extended

prior to reaching the aging limits established in the evaluation. Aging evaluations for EQ

components are time-limited aging analyses (TLAAs) for license renewal.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Environmental

Qualification (EQ) of Electrical Components Program bases documents. Specifically, the staff

reviewed the program elements and bases documents for consistency with GALL AMP X.EI.

Based on its review, the staff concludes that the applicant's Environmental Qualification (EQ) of

Electric Components Program reasonably assures management of thermal, radiation, and

cyclical aging effects for electrical equipment important to safety and located in harsh

environments. The staff finds the applicant's Environmental Qualification (EQ) of Electric

Components Program acceptable as consistent with the recommended GALL AMP X.E1,

"Environmental Qualification (EQ) of Electric Components."

Operatinq Experience. LRA Section B.1.10 states that in September 1994 the applicant

detected incorrect assumptions in EQ analyses. Corrective actions included modifications of the

assumptions, evaluation of assumptions in other program documents, and evaluation of

environmental conditions. Detection of incorrect assumptions and timely corrective actions

prove that the program is effective in assuring that equipment is maintained within its

qualification basis and qualified life.

The staff reviewed examples of the applicant's operating experience evaluations. The staff

noted that in 2002, a 10 CFR Part 21 notification was made of an error in dose units for

irradiation during the qualification testing of electrical cable connectors. The applicant evaluated

the affected equipment qualified to account for the error. Detection of incorrect assumptions

and timely corrective actions prove that the program is effective in maintaining equipment within

3-12
its qualification basis and qualified life.

In its response to a Nuclear Industry Advisory dated May 18, 2006, of an EQ issue with conduit

seals installed on Barton transmitters from 1982 to 2006, the applicant reviewed its impact on

equipment qualifications. The applicant identified all nonconforming seals per the advisory letter

and replaced them with qualified alternate conduit seals. The applicant also updated the

affected EQ files.

The overall effectiveness of the EQ of Electric Components Program is demonstrated by the

excellent operating experience for program systems, structures, and components. A snapshot

self-assessment in July 2004 revealed no issues or findings with impact on program

effectiveness.

The staff interviewed the applicant's technical personnel and also reviewed the operating

experience reports to confirm that plant-specific operating experience revealed no degradation

not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.10, the applicant provided the UFSAR supplement

for the Environmental Qualification of Electric Components Program. The staff determines that

the information in the UFSAR supplement is an adequate summary description of the program,

as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Environmental Qualification

of Electric Components Program, the staff finds all program elements consistent with the GALL

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended 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 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. LRA Section B.1.14 describes the existing

Flow-Accelerated Corrosion Program as consistent with GALL AMP XI.M17, "Flow-Accelerated

Corrosion."

The Flow-Accelerated Corrosion Program applies to safety-related and nonsafety-related

carbon steel components in systems containing high-energy fluids and carrying two-phase or

single-phase high-energy fluid greater than 2 percent of plant operating time. The program,

based on Electric Power Research Institute (EPRI) recommendations for an effective

flow-accelerated corrosion program, predicts, detects, and monitors flow-accelerated corrosion

(FAC) in plant piping and other pressure-retaining components. This program includes (a) an

evaluation to determine critical locations, (b) initial operational inspections to determine the

extent of thinning at such locations, and (c) follow-up inspections to confirm predictions or

repair or replace components as necessary.

3-13
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

*The staff interviewed the applicant's technical personnel and reviewed the Flow-Accelerated

Corrosion Program bases documents. Specifically, the staff reviewed the program elements

and bases documents for consistency with GALL AMP XI.M17.

NRC Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants" (November 6, 1987) and

NRC Generic Letter 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning" (May 2, 1989)

provide the NRC's bases for implementing flow-accelerated corrosion programs at U.S. nuclear

power plants. The staff determined that the Flow-Accelerated Corrosion Program monitors for

loss of material due to flow-accelerated corrosion in carbon steel piping components and alloy

steel components containing less than one-percent Chromium as an alloying element. This is

consistent with GALL AMP XI.M1 7, "Flow-Accelerated Corrosion," and is acceptable.

The staff also determined that the Flow-Accelerated Corrosion Program invokes the

implementation guidelines established in EPRI Report No. NSAC-202L-R2. The staff

determined the program also administratively requires the applicant to model and rank the

susceptibility of its carbon steel and low-alloy steel piping components and to schedule and

implement the UT examinations in accordance with the CHECKWORKS computer code. This

includes incorporating the results of previous UT examinations into the CHECKWORKS

modeling and using the results to re-establish the rankings of the piping and to determine and

schedule those piping locations needing UT inspection at the next inspection period. This is

consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion," and is acceptable.

Based on its review, the staff finds the applicant's Flow-Accelerated Corrosion Program

consistent with the recommended GALL AMP XI.M1 7, "Flow-Accelerated Corrosion Program,"

and acceptable.

Operating Experience. LRA Section B.1.14 states that from 2000 through 2004, FAC ultrasonic

(UT) examinations of carbon steel components in systems containing steam or treated water

detected wall thinning due to corrosion, erosion, and FAC. Corrective actions were implemented

under the site Corrective Action Program. Detection of degradation and corrective action prior

to loss of intended function proves that the program is effective for managing aging effects for

fire barrier components. There were 11 FAC UT testing examinations during Refueling Outage

(RO)16 (2004) on components in the feedwater and main steam systems. None of the

examinations detected decreased wall thickness. Absence of loss of material proves that the

program is effective for managing loss of material in carbon steel components.

During the audit and review, the staff asked the applicant how well the CHECKWORKS model

predictions compared to the actual field measurements. The applicant stated that the specific

software inputs for the JAFNPP application were verified properly and tested satisfactorily.

Although minor changes in wall thickness were detected, the measurements confirmed that,

overall, the CHECKWORKS model was conservative. The applicant also stated that it will

update, refine, and calibrate the model continually based on comparison of inspection data to

predicted wear rates.

The staff reviewed plant-specific operating experience with FAC and plant procedures. The

staff reviewed a sample of CRs and found that the applicant had evaluated potential wall

3-14
thinning from FAC properly and implemented appropriate corrective actions.

The staff reviewed the FAC records for the UT examinations that were performed during last

refueling outage. The staff determined that the carbon steel components selected for ultrasonic

inspection included a number of locations that were based on relevant industry experience

events. The staff therefore concluded that the applicant includes relevant operating experience

as part of the applicant's criteria for selecting plant carbon steel piping locations for UT

examination. The staff also determined that the applicant replaces any carbon steel piping that

have exhibited an unacceptable amount of FAC induced wear with stainless steel or

chromium-molybdenum alloy steel piping containing greater than 1-1/4 percent chromium

alloying content. The chromium levels in these steels makes the steel more resistant to FAC

than are carbon steel materials.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.15, the applicant provided the UFSAR supplement

for the Flow-Accelerated Corrosion Program. The staff reviewed this section and determined

that the information in the UFSAR supplement is an adequate summary description of the

program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Flow-Accelerated Corrosion

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.4 Non-EQ Instrumentation Circuits Test Review Program

Summary of Technical Information in the Application. LRA Section B.1.18 describes the new

Non-EQ Instrumentation Circuits Test Review Program as consistent with GALL AMP XI.E2,

"Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits."

The Non-EQ Instrumentation Circuits Test Review Program reviews calibration or surveillance

results for non-EQ electrical cables in circuits with sensitive, high-voltage, low-level signals.

Most neutron flux monitoring system cables and connections are calibrated as part of the

instrumentation loop calibration at its normal frequency, which sufficiently indicates the need for

corrective actions based on acceptance criteria for instrumentation loop performance.

Calibration results will be reviewed every 10 years. Neutron flux monitoring system cables

disconnected during instrument calibrations will be tested at least every 10 years by a proven

method for detecting deterioration for the insulation system. Under the corrective action

program, there will be an engineering evaluation when test acceptance criteria are not met and

corrective actions, including modified inspection frequency, will maintain the intended functions

of the cables consistently with the CLB. for the period of extended operation.

3-15
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Non-EQ

Instrumentation Circuits Test Review Program bases documents. Specifically, the staff

reviewed the program elements and bases documents for consistency with GALL AMP XI.E2.

The scope of GALL AMP XI.E2 applies to the cable system (cables and connections).

During the audit and review, the staff asked the applicant whether the tests include both cables

and connections.

In its response, the applicant clarified that the Non-EQ Instrumentation Circuits Test Review

Program includes both cables and connections (cable system) within the scope of license

renewal.

Based on its review, the staff finds the applicant's response acceptable because it is consistent

with GALL AMP XI.E2 recommendation.

The staff reviewed portions of the applicant's Non-EQ Instrumentation Circuits Test Review

Program for which the applicant claimed consistency with GALL AMP XI.E2 and found them

consistent. The staff finds the applicant's Non-EQ Instrumentation Circuits Test Review

Program consistent with recommended GALL AMP XI.E2, "Electrical Cables and Connections

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in

Instrumentation Circuits," and acceptable.

Operating Experience. LRA Section B.1.18 states that the Non-EQ Instrumentation Circuits

Test Review Program is a new program. Plant and industry operating experience will be

considered in the development of this program. Industry operating experience that forms the

basis for the program is described in the operating experience element of the GALL Report

program description.

The staff finds that plant-specific operating experience is consistent with that in the GALL

Report program description and that this new program will reasonably assure management of

aging effects so that components will continue to perform their intended functions consistently

with the CLB for the period of extend operation. With additional operating experience lessons

learned can be used to adjust the program as needed.

The staff interviewed the applicant's technical personnel and also reviewed operating

experience reports that plant-specific operating experience revealed no degradation not

bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.20, the applicant provided the UFSAR supplement

for the Non-EQ Instrumentation Circuits Test Review Program. The staff reviewed the

applicant's license renewal commitment list in LRA Amendment 5, Attachment 1, Revision 1,

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dated February 1, 2007, and confirmed that this new program is Commitment No. 9

(JAFP-06-0109, dated July 31, 2006) to be implemented before the period of extended

operation.)

The staff reviewed this section and determined that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Non-EQ Instrumentation

Circuits Test Review Program, the staff finds all program elements consistent with the GALL

Report. The staff concludes that the applicant will have a program 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).

3.0.3.1.5 Non-EQ Insulated Cables and Connections Program

Summary of Technical Information in the Application. LRA Section B. 1.19 describes the new

Non-EQ Insulated Cables and Connections Program as consistent with GALL AMP XI.E1,

"Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements."

The Non-EQ Insulated Cables and Connections Program will provide reasonable assurance

that intended functions of insulated cables and connections exposed to adverse environments

of heat, radiation, and moisture can be maintained consistently with the CLB through the period

of extended operation. An adverse environment is significantly more severe than the specified

service condition for the insulated cable or connection. This program addresses plant cables

and connections installed in adverse environments that are accessible. This program can be

thought of as a sampling program. Selected cables and connections from accessible areas,

representative of all cables in adverse environments, will be inspected and if an unacceptable

condition or situation for a cable or connection in the sample is detected, a determination will be

made whether the condition or situation affects other accessible cables or connections. The

sample size will be increased based on the determination. The program will be implemented

fully prior to the period of extended operation.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Non-EQ Insulated

Cables and Connections Program and Non-EQ Instrumentation Circuits Test Review Program

bases documents. Specifically, the staff reviewed the program elements and bases documents

for consistency with GALL AMP XI.E1.

The staff finds the applicant's Non-EQ Insulated Cables and Connections Program consistent

with recommended GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10

CFR50.49 Environmental Qualification Requirements," and acceptable.

Operatinq Experience. LRA Section B. 1.19 states that the Non-EQ Insulated Cables and

Connections Program is a new program. Plant and that industry operating experience will be

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considered in the development of this program. Industry operating experience that forms the

basis for the program is described in the operating experience element of the GALL Report

program description. The plant-specific operating experience is consistent with the operating

experience in the GALL Report program description and that this new program will reasonably

assure management of aging effects so that components will continue to perform their intended

functions consistently with the CLB for the period of extend operation. With additional operating

experience, lessons learned can be used to adjust the program as needed.

The staff also interviewed the applicant's technical personnel and reviewed the operating

experience reports and confirmed that plant-specific operating experience revealed no

degradation not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.21, the applicant provided the UFSAR supplement

for the Non-EQ Insulated Cables and Connections Program. The staff reviewed the applicant's

license renewal commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated

February 1, 2007, and confirmed that this new program is Commitment No. 10 (JAFP-06-0109,

dated July 31, 2006) to be implemented before the period of extended operation.

The staff reviewed this section and determined that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Non-EQ Insulated Cables

and Connections Program, the staff finds all program elements consistent with the GALL

Report. The staff concludes that the applicant will have a program 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 One-Time Inspection Program

Summary of Technical Information in the Application. LRA Section B.1.21 describes the new

One-Time Inspection Program as consistent with GALL AMP XI.M32, "One-Time Inspection"

and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping."

The program will include one activity to verify effectiveness of an AMP and activities to confirm

the absence of aging effects as described below:

Water chemistry control programs One-time inspection activity will verify the effectiveness

of the water chemistry control AMPs by confirming no

occurrence of unacceptable cracking, loss of material,

or fouling.

Internal surfaces of high-pressure coolant injection One-time inspection will confirm no loss of material or

system components containing untreated air. loss so insignificant that no AMP is warranted.

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Surfaces of carbon steel and cast iron plant drain One-time inspection will confirm no loss of material or

components normally exposed to indoor air loss so insignificant that no AMP is warranted

Internal surfaces of carbon steel emergency diesel One-time inspection will confirm no cracking and loss

generator system components containing untreated air of material or cracking and loss so insignificant that no

AMP is warranted

Internal surfaces of stainless steel and aluminum One-time inspection will confirm no loss of material or

components in the radioactive waste system containing loss so insignificant that no AMP is warranted

raw water

Internal surfaces of stainless steel and copper alloy One-time inspection will confirm no loss of material or

components in the raw water treatment system loss so insignificant that no AMP is warranted

containing raw water

Internal surfaces of copper alloy components in the One-time inspection will confirm no losslof material or

plumbing, sanitary and lab system and the city water loss so insignificant that no AMP is warrbnted

system containing raw water

Internal surfaces of scram accumulators One-time inspection will confirm no loss of material or

loss so insignificant that no AMP is warranted

Small bore piping in the reactor coolant system and One-time inspection will confirm no cracking and

associated systems that form the reactor coolant reduction of fracture toughness or cracking and

pressure boundary reduction so insignificant that no AMP is warranted

Reactor vessel flange leakoff line One-time inspection will confirm no cracking or

cracking so insignificant that no AMP is warranted

Main steam flow restrictors (cast austenitic stainless One-time inspection will confirm no loss of material,

steel (CASS)) cracking, or reduction of fracture toughness or loss,

cracking, or reduction so insignificant that no AMP is

warranted

The One-Time Inspection Program will include the following elements: (a) determination of the

sample size based on an assessment of fabrication materials, environment, plausible aging

effects, and operating experience, (b) identification of the inspection locations for the aging

effect in the system or component, (c) determination of the inspection technique, including

acceptance criteria that would be effective in managing the aging effect for which the

component is inspected, and (d) evaluation of the need for follow-up inspections to monitor the

progression of any aging degradation. When a one-time inspection reveals evidence of an

aging effect, evaluation of the inspection results will indicate appropriate corrective actions.

There will be an inspection within 10 years prior to the period of extended operation.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the One-Time Inspection

Program bases documents. Specifically, the staff reviewed the program elements and bases

documents for consistency with GALL AMPs XI.M32 and XI.M35.

The staff noted in Attachment 2 of the program basis document for the applicant's One-Time

Inspection Program a table describing various program elements. The table described in

general terms the components and the sample population to be inspected.

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During the audit and review, the staff asked the applicant how the sample size for each

inspection will be developed and expanded if degradation is detected.

In its response, the applicant stated that the sample size will be based on

EPRI 107514,"Age-Related Degradation Inspection Method and Demonstration," Chapter 4,

which outlines a method for determining the number of inspections required for 90-percent

assurance that 90 percent of the population experiences no degradation. Components with the

same material-environment combinations at other facilities may be included in the sample. The

program provides for increasing inspection sample size and locations in the event that aging

effects are detected. Unacceptable inspection findings are evaluated in accordance with the

JAFNPP corrective action process to determine the need for subsequent (including periodic)

inspections and for monitoring and trending the results.

For verification of the effectiveness of the water chemistry programs, the scope will include a

representative sample of the components crediting the Water Chemistry Program. Since

operating experience identified a history of low oxygen and high iron content in the reactor

building closed loop cooling (RBCLC) system, the sample population will specifically include

components in this system. For confirmation that aging is not occurring or is so insignificant that

an AMP is not required, the table in Attachment 2 identifies specific components that will be

inspected in the systems crediting the One-Time Inspection Program. The staff determined that

the scope of this program is adequately described.

The table in Attachment 2 to the AMP basis document also shows the inspection techniques

and the parameters to be monitored to detect the effects of aging managed. The parameters

monitored include wall thickness, fouling, and the extent of cracking. Reduction of fracture

toughness is also a parameter to be monitored by inspection of specific CASS components for

the extent of cracking. Inspection techniques include visual examination, surface techniques,

UT testing, and radiography. The inspections will be by qualified personnel following

procedures consistent with ASME Boiler and Pressure Vessel Code (ASME Code), Section XI,

and with 10 CFR Part 50, Appendix B.

The staff determined that the parameters to be monitored are consistent with the aging effects

which the LRA credits this program. The inspection techniques are proven methods for

detecting loss of wall thickness, fouling, and the extent of cracking, common in the industry,

and, therefore, acceptable for the purposes of this AMP. For the detection of loss of fracture

toughness, the staff determined that the One-Time Inspection Program is not sufficient because

it does not include fracture toughness measurements and at least two measurements are

needed to determine whether component fracture toughness has decreased. The staff

recognizes that this AMP will inspect specific CASS components for the extent of cracking as

an indicator of loss of fracture toughness. The staff finds this AMP acceptable for non-RCPB

components. However, the staff finds that the One-Time Inspection Program alone is not

sufficient to manage loss of fracture toughness for RCPB components since a reduction in

fracture toughness will accelerate the propagation of existing cracks, which could lead to a loss

of component intended function.

Finally, the table in Attachment 2 of the program basis document shows the acceptance criteria

for whether corrective actions are needed based on inspection results. For inspections to detect

cracking or corrosion, the acceptance criteria require corrective actions if any significant

cracking or corrosion is detected. For UT inspections, the acceptance criteria require a

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comparison of measured thickness to predetermined limits with an evaluation of any

degradation noted. The staff determined that these acceptance criteria will assure AMP

effectiveness or no significant aging degradation, the two purposes for which the applicant

credits this program.

The staff noted that the One-Time Inspection Program also will manage aging of small-bore

piping, including socket welds. The staff considers the requirements of ASME Code Section XI,

Subsection IWB acceptable for aging management of small-bore piping. The staff discussed

the inspection of small-bore piping with the applicant and determined that its Risk-lnformed

Inservice Inspection (RI-ISI) Program monitors pipingand piping elements. The inspections are

in- accordance with ASME Code Section Xl inservice inspection (ISI) requirements. The

Risk-Informed Inservice Inspection Program identifies risk-important. pipe segments based upon

contribution to plant risk. Each pipe segment may have multiple pipe welds inspected with the

segment. During each ISI interval selected pipe segments are inspected by radiography, UT

testing, and surface techniques. Radiography is a volumetric examination, so when pipe

segments with socket welds are inspected the applicant takes credit for volumetric inspections.

Socket welds are required for piping 2 inches or less.

During the audit and review, the staff asked the applicant for additional details on the

small-bore piping inspections for the period of extended operation to inspect piping socket

welds.

In its response the applicant stated:

JAFNPP meets the requirements of ASME Section Xl with respect to the inspection of

Class 1 small bore piping and socket welds through implementation of a risk-informed

ISI program. During the period of extended operation, as required by 10 CFR 50.55a,

JAFNPP will meet the requirements of ASME Section XI or implement an approved

alternative such as the existing risk-informed ISI Program.

The ISI program for small-bore piping at JAFNPP uses nondestructive

examination (NDE) techniques to detect and characterize flaws. Three different

types of examinations are volumetric, surface, and visual. Examinations

performed on pipe segments within the 3rd interval inspection program have

included the examination of associated socket welds. The pipe segments have

been examined for FAC and thermal fatigue by ultrasonic's, radiography and

surface examination (dependent upon flaw mechanism) that captures the

associated socket welds verifying integrity. Surface examinations, such as

magnetic particle or dye penetrant testing, are used to locate surface flaws.

Three levels of visual examinations are specified. VT-i visual examination is

conducted to assess the condition of the surface of the part being examined,

looking for cracks and symptoms of wear, corrosion, erosion or physical

damage. It can be done with either direct visual observation or with remote

examination using various optical and video devices. VT-2 visual examination is

conducted specifically to locate evidence of leakage from pressure retaining

components (periodic pressure tests). While the system is under pressure for a

leakage test, visual examinations are conducted to detect direct or indirect

indication of leakage. VT-3 visual examination is conducted to determine general

mechanical and structural condition of components and supports and to detected

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discontinuities and imperfections.

A preliminary review of Class 1 piping was performed to derive an estimated

number of Class 1 socket welds and/or piping segments in accordance with the

Risk-Informed Inservice Inspection Program (RI-ISI). The estimated total of

Class 1 socket welds and/or piping segments is eight piping segments that are

inspected in each ISI interval out of the total segments identified in the ISI

program and includes approximately 15 welds out of the total class I socket weld

population. The total number of inspections conducted during the 3rd ten-year

ISI Interval estimated at approximately 5% of the total segments and 1% of the

total welds.

Examination Category B-F welds are scheduled and examined as part of the

IGSCC Augmented Inspection Program. Extent and frequency of examinations

are in accordance with the Risk-Informed IS[ Program.

The staff reviewed the applicant's response and determined that the applicant's small-bore

piping inspections are consistent with the staff-approved Risk-Informed Inservice Inspection

Program and meet ASME Code Section XI, Subsection IWB, small-bore piping requirements.

The staff finds the applicant's One-Time Inspection Program consistent with recommended

GALL AMP XI.M32, "One-Time Inspection," and GALL AMP XI.M35, "One-Time Inspection of

ASME Code Class 1 Small-Bore Piping," and acceptable.

Operating Experience. LRA Section B.1.21 states that there is no operating experience for the

new One-Time Inspection Program. The elements comprising this program are consistent with

industry practice, which provides reasonable assurance that the One-Time Inspection Program

will manage aging effects so that components will continue to perform their intended functions

consistently with the CLB for the period of extend operation.

The staff reviewed the License Renewal Project Operating Experience Review Report in

general for small-pipe issues. This report provides information from condition reports and

program owner interviews and covers the last five years.

The staffs review confirmed that there had been no failures of Class 1 piping less than 4 inches

NPS within the scope of this program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.23, the applicant provided the UFSAR supplement

for the One-Time Inspection Program. In its letter dated February 1, 2007 (LRA Amendment 5),

the applicant submitted Revision 1 to the license renewal commitment list. The applicant

included Commitment No. 12 (JAFP-06-0109 dated July 31, 2006) for implementation of this

new program. The applicant states that this program will be implemented prior to

October 17, 2014.

The staff reviewed this section, including Commitment No. 12, and determined that the

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information in the UFSAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's One-Time Inspection

Program, the staff finds all program elements consistent with the GALL Report. 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 Selective Leaching Program

Summary of Technical Information in the Application. LRA Section B.1.25 describes the new

Selective Leaching Program as consistent with GALL AMP XI.M33, "Selective Leaching of

Materials."

The Selective Leaching Program will ensure the integrity of components made of cast iron,

bronze, brass, and other alloys exposed to raw water, treated water, soil, or other environments

that may lead to selective leaching. The program will include a one-time visual inspection and

hardness measurement of selected components that may be susceptible to determine whether

loss of material due to selective leaching has occurred and whether it affects the ability of the

components to perform their intended function for the period of extended operation. The

program will be implemented fully prior to the period of extended operation (Commitment

No. 15 (JAFNPP-06-0109, dated July 31, 2006)).

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Selective Leaching

Program bases documents. -Specifically, the staff reviewed the program elements and bases

documents for consistency with GALL AMP XI.M33.

The staff reviewed Selective Leaching Program portions for which the applicant claims

consistency with GALL AMP XI.M33 and finds them consistent. The staff determined that the

program element descriptions in the Selective Leaching Program conformed to corresponding

program elements in GALL AMP XI.M33, "Selective Leaching of Materials." The staff finds the

applicant's Selective Leaching Program consistent with recommended GALL AMP XI.M33,

"Selective Leaching of Materials," and acceptable.

Operating Experience. LRA Section B.1.25 states that the Selective Leaching Program is a new

program. The elements which comprise this program (e.g., the scope of the inspections and

inspection techniques) are consistent with industry practice and staff expectations. As such,

operating experience provides reasonable assurance that the Selective Leaching Program will

manage aging effects so that components will continue to perform their intended functions

consistently with the CLB for the period of extended operation.

During the audit and review, the applicant stated there is no programmatic operating experience

available for this new program but that there had been no selective leaching. Also, industry

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operating experience with graphitization of cast iron components from long-term submersion in

salt water is not applicable because there are no any salt water systems but the applicant will

consider other industry operating experience during program implementation. The applicant

stated -that it would monitor water chemistry to control pH and concentration of corrosive

contaminants and to minimize dissolved oxygen as part of the Water Chemistry Program to

reduce selective leaching effectively.

The staff interviewed the applicant's technical personnel and also reviewed the operating

experience program basis document and confirmed that plant-specific operating experience

revealed no degradation not bounded by industry operating experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.27, the applicant provided the UFSAR supplement

for the Selective Leaching Program. The staff reviewed the applicant's license renewal

commitment list in LRA Amendment 5, Attachment 1, Revision 1 dated February 1, 2007, and

confirmed that this new program is Commitment No.15 (JAFP-06-0109, dated July 31, 2006) to

be implemented before the period of extended operation.

The staff reviewed this section and determined that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Selective Leaching Program,

the staff finds all program elements consistent with the GALL Report. The staff concludes that

the applicant will have a program 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 Masonry Wall Program

Summary of Technical Information in the Application. LRA Section B.1.27.1 describes the

existing Masonry Wall Program as consistent with GALL AMP XI.S5, "Masonry Wall Program."

The Masonry Wall Program manages aging effects so that the evaluation basis established for

each masonry wall within the scope of license renewal remains valid through the period of

extended operation. The program includes all masonry walls performing intended functions in

accordance with 10 CFR 54.4. Included components are masonry walls required by

10 CFR 50.48, radiation-shielding masonry walls, and masonry walls with the potential to affect

safety-related components. Masonry walls are visually examined at a frequency selected to

ensure no loss of intended function between inspections.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Masonry Wall

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Program bases documents. Specifically, the staff reviewed the program elements and bases

documents for consistency with GALL AMP XI.S5.

The staff noted that the Masonry Wall.Program includes the guidance and lessons learned from

Office of Inspection and Enforcement Bulletin 80-11 and Information Notice 87-67.

During the audit and review, the staff asked for the visual examination frequency for the

program and its technical basis.

In its response, the applicant stated that Maintenance Rule visual inspections are at least every

five years to ensure no loss of intended function between inspections. The absence of

operating experience with significantly degraded masonry walls indicates that this frequency is

appropriate. The applicant also stated that no additional masonry walls have been added to the

scope of this program, which, including visual examination frequencies, is consistent with GALL

AMP XI.S5.

The staff reviewed the Masonry Wall Program portions for which the applicant claims

consistency with GALL AMP XI.S5 and finds them consistent. The staff finds the applicant's

Masonry Wall Program consistent with recommended GALL AMP XI.S5, "Masonry Wall

Program," and acceptable.

Operating Experience. LRA Section B.1.27.1 states that inspections in 2000 revealed that each

of the two block walls separating the emergency diesel generator (EDG) rooms was separated

slightly at the ends where they connect to the reinforced concrete walls. Inspections in 2004

detected cracks at interfaces with doors, in the west block wall of the east electric bay and in

the main control room inner vestibule masonry block wall. The cracks did not affect the

structural integrity of the walls and were repaired with new grout. Detection of degradation and

corrective action prior to loss of intended function prove that the program is effective for

managing cracking of masonry walls and masonry wall joints. A QA surveillance in August 2003

revealed no. issues or findings with impact on program effectiveness.

The staff reviewed the operating experience reports and also interviewed the applicant's

technical personnel to confirm that plant operating experience revealed no degradation not

bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.29, the applicant provided the UFSAR supplement

for the Masonry Wall Program. The staff reviewed this section and determined that the

information in the UFSAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Masonry Wall Program, the

staff finds all program elements consistent with the GALL Report. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

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for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d).

3.0.3.1.9 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel Program

Summary of Technical Information in the Application. LRA Section B.1.28 describes the new

Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

Program as consistent with GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation

Embrittlement of Cast Austenitic Stainless Steel."

The Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

Program assures that reduction of fracture toughness due to thermal aging and radiation

embrittlement will not cause loss of intended function. This program will evaluate cast austenitic

stainless steel components in the reactor vessel internals and require nondestructive

examinations as appropriate. EPRI, the Boiling Water Reactor (BWR) Owners Group, and other

industry groups are focused on reactor vessel internals for a better understanding of aging

effects. Future Boiling Water Reactor Vessel Internals Project (BWRVIP) reports, EPRI reports,

and other industry operating experience will be additional bases for evaluations and inspections

under this program. This program will supplement reactor vessel internals inspections required

by the BWR Vessel Internals Program to assure that aging effects do not cause loss of reactor

vessel internals intended functions during the period of extended operation. The program will be

implemented fully prior to the period of extended operation.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Thermal Aging and

Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program bases documents.

Specifically, the staff reviewed the program elements and bases documents for consistency

with GALL AMP XI.M13. The staffs review indicated that this program will include the criteria of

GALL Report Chapter XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast

Austenitic Stainless Steel (CASS)."

Based on its review, the staff finds the applicant's Thermal Aging and Neutron Irradiation

Embrittlement of Cast Austenitic Stainless Steel Program consistent with recommended GALL

AMP X.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS)," and acceptable.

Operatingq Experience. LRA Section B.1.28 states that the Thermal Aging and Neutron

Irradiation Embrittlement of Cast Austenitic Stainless Steel Program is a new program. Industry

operating experience that forms the basis for the program is described in the operating

experience element of the GALL Report program description. The applicant also states that

plant-specific operating experience is consistent with the operating experience in the GALL

Report program description.

During the audit and review, the staff asked for additional information on plant-specific

operating experience with CASS components.

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In its response, the applicant stated that it periodic examination of internal reactor vessel

components has detected no degradation.

The staff also reviewed the operating experience in the basis document and interviewed the

applicant's technical personnel to confirm that there is no industry operating experience with

thermal aging and neutron irradiation embrittlement of CASS.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.31, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

Program. The staff reviewed the applicant's license renewal commitment list in LRA

Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and confirmed that this

program is Commitment No. 17 (JAFP-06-0109 dated July 31, 2006) to be implemented before

the period of extended operation.

The staff reviewed this section and determined that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Thermal Aging and Neutron

Irradiation Embrittlement of Cast Austenitic Stainless Steel Program, the staff finds all program

elements consistent with the GALL Report. The staff concludes that the applicant will have a

program 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).

3.0.3.1.10 Water Chemistry Control - BWR Program

Summary of Technical Information in the Application. LRA Section B.1.29.2 describes the

existing Water Chemistry Control - BWR Program as consistent with GALL AMP XI.M2, "Water

Chemistry."

The Water Chemistry Control - BWR Program manages aging effects caused by corrosion and

cracking mechanisms. The program monitors and controls water chemistry based on EPRI

Report 1008192 (BWRVIP-1 30), which has three sets of guidelines: one for primary water, one

for condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water.

EPRI guidelines in BWRVIP-130 also include recommendations for controlling water chemistry

in the torus, condensate storage tanks, demineralized water storage tanks, and the spent fuel

pool. The Water Chemistry Control -, BWR Program optimizes primary water chemistry to

minimize the potential for loss of material and cracking by limiting reactor coolant system levels

of contaminants that could cause loss of material and cracking. Additionally, the applicant has

instituted hydrogen water chemistry and noble metal chemical addition to limit the potential for

intergranular stress corrosion cracking (IGSCC) through the reduction of dissolved oxygen in

the treated water.

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Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical personnel and reviewed the Water Chemistry

Control - BWR Program bases documents. Specifically, the staff reviewed the program

elements and bases documents for consistency with GALL AMP XI.M2.

GALL AMP XI.M2, "Water Chemistry," recommends that water chemistry programs be based

on the guidelines established in EPRI Report No. BWRVIP-29 or later versions of the report,

such as EPRI Report Nos. BWRVIP-79 or BWRVIP-130. The applicant's Water Chemistry

Program is based on conformance with the recommended water chemistry guidelines in EPRI

Report No. BWRVIP-1 30. The staff determined that this is acceptable because the

recommendations in EPRI Report No. BWVIP-130 are endorsed in GALL AMP XI.M2, "Water

Chemistry," as an acceptable version of the report for implementation.

During the audit and review, the staff asked for information on other water chemistry activities

(e.g., hydrogen water chemistry).

In its response, the applicant stated that it had implemented hydrogen water chemistry in 1988

to mitigate cracking in the recirculation piping and noble metal chemical addition in 1999 and

reapplied it in 2004. The applicant also instituted Zinc addition in 1989 for dose rate reduction.

The staff finds the applicant's Water Chemistry Control - BWR Program consistent with the

recommended GALL AMP XI.M2 and acceptable.

Operating Experience. LRA Section B.1.29.2 states that from 2000 through 2004 there were

several CRs of adverse trends in parameters monitored by the Water Chemistry Control - BWR

Program. Corrective actions were taken within the corrective action program to preclude the

parameters from reaching unacceptable values. In the same period, there were a few incidents

in which parameters monitored by the Water Chemistry Control - BWR Program exceeded

EPRI action Level 1 acceptance criteria. Monitoring frequency was increased and the

parameters returned to the prescribed normal operating range as soon as possible (within the

96 hours permitted by action Level 1). In August 2003, reactor water sulfates were briefly above

the EPRI action Level 2 acceptance criteria. Flow disturbance through the condensate

demineralizers caused resin fines and flow channeling when restored to service. Corrective

action was taken to remove condensate beds from service and clean them. In June 2004, while

the Chemistry Department obtained a sample for analysis from the standby liquid control tank

(1 1TK-1), several small particles were seen floating inside the tank. The next month's sample

showed less particulate and later samples have shown none. Corrective actions included

procedure modification to require sparge air sampling if particulate becomes evident again to

determine whether this air could be the source of contamination. The Cycle 16 average

chemistry data for primary and associated systems compares favorably when compared to the

action Level 1 parameter values from the BWR Water Chemistry Guidelines. Sulfate and

chloride concentrations were very low, while average feedwater iron went up this cycle.

Feedwater average iron and copper concentrations were affected by shutdowns and power

reductions during the cycle along with reduced condensate temperatures and ultrasonic resin

cleaning skid maintenance problems. Corrective actions were taken to repair and optimize the

ultrasonic resin cleaning skid and additional improvements to the condensate demineralizer

system have been pursued. A 2001 self-assessment revealed that sample system flow rates for

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the corrosion product metal samplers for feedwater and condensate may not be high enough

for an adequate representative sample. The sample lines were replaced during the first quarter

of 2004 with lines that deliver at least 6 linear feet/second. Continuous confirmation of water

quality and -timely corrective action prove that the program is effective in managing loss of

material for applicable components. A QA surveillance in 2004 revealed no issues or findings

with impact on program effectiveness.

The staff also reviewed operating experience reports and confirmed that plant-specific

operating experience shows no effects of aging for systems and components within the scope

of this program not bounded by industry operating experience. In plant-specific operating

experience loss of material and cracking in components exposed to reactor water have been

prevented., These effects of aging are consistent with industry operating experience, and this

.AMP includes aging management activities (e.g., control of contaminant concentrations in

reactor water) appropriate to prevent these effects of aging for reactor coolant pressure

boundary components. The applicant further stated during the audit that corrective actions were

taken prior to either a loss of component intended function or a deviation from normal

contaminant level limits in the reactor water. The staff reviewed two CRs as examples of such

activities and found that the applicant took appropriate corrective actions to remedy water

chemistry contaminant level fluctuations.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.33, the applicant provided the UFSAR supplement

for the Water Chemistry Control - BWR Program. The staff reviewed this section and

determined that the information in the UFSAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control -

BWR Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

LRA Appendix B, states that the following AMPs are, or will be, consistent with the GALL Report

with exceptions or enhancements:

" Buried Piping and Tanks Inspection Program

" BWR CRD Return Line Nozzle Program

" BWR Feedwater Nozzle Program

" BWR Penetrations Program

" BWR Stress Corrosion Cracking Program

• BWR Vessel ID Attachment Welds Program

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* BWR Vessel Internals Program

" Diesel Fuel Monitoring Program

* External Surfaces Monitoring Program

* Fatigue Monitoring Program

* Fire Protection Program

* Fire Water System Program

* Metal-Enclosed Bus Inspection Program

* Oil Analysis Program

* Reactor Head Closure Studs Program

* Reactor Vessel Surveillance Program

* Service Water Integrity Program

* Structures Monitoring Program

* Water Chemistry Control - Closed Cooling Water Program

* Bolting Integrity Program

For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s)

and/or enhancement(s), the staff performed an audit and review to confirm that those attributes

or features of the program for which the applicant claimed consistency with the GALL Report

were indeed consistent. The staff also reviewed the exception(s) and/or enhancement(s) to the

GALL Report to determine whether they were acceptable and adequate. The results of the

staffs audits and reviews are documented in the following sections.

3.0.3.2.1 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. LRA Section B. 1.1 describes the new

Buried Piping and Tanks Inspection Program as consistent, with exception, with GALL

AMP XI.M34, "Buried Piping and Tanks Inspection."

This program includes (a) preventive measures to mitigate corrosion and (b) inspections to

manage the effects of corrosion on the pressure-retaining capability of buried carbon steel,

copper alloy, gray cast iron, and stainless steel components. Preventive measures are in

accordance with standard industry practice for maintaining external coatings and wrappings.

Buried components are inspected when excavated during maintenance. If trending within the

corrective action program identifies susceptible locations, the areas with a history of corrosion

problems are evaluated for the need for additional inspection, alternate coating, or replacement.

There will be a focused inspection within the first ten years of the period of extended operation

unless an opportunistic inspection occurs within this ten-year period. This program will be

implemented fully prior to the period of extended operation.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical personnel and reviewed the Buried Piping and

Tanks Inspection Program bases documents. Specifically, the staff reviewed the program

elements and bases documents for consistency with GALL AMP XI.M34.

In reviewing this AMP, the staff noted that LRA Section B.1.1 states that this program will

include an opportunistic or focused inspection within the first ten years of the period of extended

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operation.

During the audit and review, the staff asked the applicant whether there will be an inspection

during the ten-year period immediately prior to the period of extended operation, as

recommended by the GALL Report.

In its response, the applicant stated that, if there is no opportunistic inspection during the

ten-year period immediately prior to the period of extended operation, there will be a focused

inspection. The applicant further stated it would modify the program basis document to clarify

this point. By the end of its audit and review the staff verified that the applicant had revised the

basis document to state that either focused or opportunistic inspection, will be performed during

the ten-year period immediately prior to entering the period of extended operation, as

recommended in the GALL Report. The staff finds the revision is consistent with the GALL

Report recommendations and acceptable.

The staff finds the applicant's Buried Piping and Tanks Inspection Program acceptable because

it is consistent with GALL AMP XI.M34, "Buried Piping and Tanks Inspection," with an

exception:

Exception. The LRA states an exception to the GALL Report program element "detection of

aging effects," specifically:

Inspections via methods that allow assessment of pipe condition without

excavation may be substituted for inspections requiring excavation solely for the

purpose of inspection.

During the audit and review, the staff asked the applicant for additional details on its inspection

methods, including selection process criteria, method qualification, inspection personnel

training, and corrective actions.

In its response, the applicantstated that the inspection method will assess piping condition

effectively without the threat in excavation of damage to the coating. The applicant anticipates

that such methods will assess more extensive buried piping portions than would the method of

excavation for visual inspections at a sampling of locations. The purpose of this exception is to

allow the use of more effective state-of-the-art inspection techniques (e.g., phased array UT) in

lieu of piping excavation with the potential for damage to the piping and its coating. As an

example, phased array UT examination qualification would be through demonstration by ASME

Code Section V guidelines and industry guidance. Personnel performing the examination would

be trained to Level II in accordance with the applicant's nondestructive testing practice.

The staff determined that this exception will use new technologies with a lower risk of damage

to the coatings on buried components while providing information on component condition

equivalent to that provided by excavation. The applicant has stated that the technique it uses

will be qualified by accepted industry guidance (e.g., ASME or National Association of

Corrosion Engineers) and performed by trained operators using current Entergy practices. The

staff finds that these prerequisites assure inspection results adequate for the intended purpose.

The proposed exception also eliminates the possibility of inadvertent damage during inspection

to assess the component. On these bases, the staff finds this exception acceptable.

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Operatinq Experience. LRA Section B.1.1 states that the Buried Piping and Tanks Inspection

Program is a new program. Industry operating experience that forms the basis for the program

is described in the operating experience element of the GALL Report program description.

Plant-specific operating experience is consistent with the operating experience in the GALL

Report program description and provides reasonable assurance that the Buried Piping and

Tanks Inspection Program will manage the aging effects so that components will continue to

perform their intended functions consistently with the CLB for the period of extend operation.

During the audit and review, the staff asked for additional details on plant-specific operating

experience with buried components for each material-environment combination within the scope

of license renewal.

In its response, the applicant stated that a search of CRs from the early 1990s to present found

one report, related to buried piping and tanks, of a leak in the hydrogen supply buried piping

between the storage facility and the turbine building. The applicant determined the root cause

of the leak to be poor application of the protective coatings, not aging-related. The corrective

action was to replace the degraded section of piping. In addition to this event, several fire

protection system buried valves were excavated and none showed evidence of corrosion. The

staff reviewed the CR and confirmed the applicant's claim that this event was not caused by

age-related degradation of the coatings. The staff determined that this operating experience

shows no aging mechanisms not bounded by industry operating experience.

The staff also reviewed operating experience reports and confirmed that plant-specific

operating experience shows no aging effects for systems and components within the scope of

this program not bounded by industry operating experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.1, the applicant provided the UFSAR supplement for

the Buried Piping and Tanks Inspection Program. The staff reviewed the applicant's license

renewal commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated

February 1, 2007, and confirmed that this new program is Commitment No. 1 (JAFP-06-0109

dated July 31, 2006) to be implemented before the period of extended operation.

The staff reviewed this section and determines that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Buried Piping and Tanks

Inspection Program, the staff finds those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception

and the associated justifications and finds that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant will

have a program that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

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3.0.3.2.2 BWR CRD Return Line Nozzle Program

Summary of Technical Information in the Application. LRA Section B. 1.2 describes the existing

BWR CRD Return Line Nozzle Program as consistent, with exceptions and enhancement, with

GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle."

Under this program, the applicant has cut and capped the CRD return line nozzle to mitigate

cracking and continues inservice inspections (ISIs) to monitor the effects of crack initiation and

growth on the intended function of the CRD return line nozzle and cap. In 2000, a structural

weld overlay was made over a crack in the CRD return line nozzle-to-cap weld. The

nickel-based Alloy 52 weld metal used in the overlay is highly resistant to stress corrosion,

which was determined to be the cause of the cracking.

Staff Evaluation. During its audit and review, the staff reviewed the exceptions and

enhancement to determine whether the AMP, with the exceptions and enhancement, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed the BWR CRD Return

Line Nozzle Program bases documents. Specifically, the staff reviewed the program elements

and bases documents for consistency with GALL AMP XI.M6.

LRA Section B.1.2 states that the applicant has cut and capped the CRD return line nozzle to

mitigate cracking.

During the audit and review, the staff asked for additional information on these activities.

In its response, the applicant stated that it had detected a through-wall weld defect in the

three-inch CRD return piping upstream of the vessel penetration in 1983. Following

NUREG-0619 recommendations for corrective actions, during the 1985 refueling outage (RO 7)

the applicant removed the nozzle safe end and thermal sleeve and then cut and capped the

CRD return line nozzle (N9). The materials in both the cap (Inconel 600) and the weldment

(Inconel 182) are susceptible to IGSCC; therefore, although this dissimilar weld (ASME Code

Category B-F weld) weld is on a three-inch nozzle, the applicant inspects it under the IGSCC

Program, which applies to piping equal to or greater than four inches. The applicant determined

that inspection of this weld is important because its material is susceptible to IGSCC; therefore,

it was included in the IGSCC Program.

The staff determined that since the CRD return line nozzle was capped in 1985 the subject weld

has been inspected periodically by volumetric (UT) examinations under the IGSCC Program in

lieu of the ASME Code-required surface examination for piping less than four-inch NPS. The

staff finds this program acceptable because volumetric examination can and surface

examination cannot detect cracks originating from inside the nozzle.

Further, the LRA states that in 2000, a structural weld overlay was installed over a crack in the

CRD return line nozzle-to-cap weld.

During the audit and review, the staff asked for additional information on the installation.

In its response, the applicant stated that, since the nozzle was capped, inspections of this weld

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revealed no indications of degradation until the inspection in 2000 (RO 14) revealed an

unacceptable flaw on the inside surface of the weld. After approval by the staff, the applicant

repaired the nozzle weld by applying a weld overlay (nickel-based Alloy 52) rather than

removing the crack by grinding as recommended in NUREG-0619. Results of a UT examination

of the completed weld overlay were acceptable. The applicant continues the UT examinations

of this weld under the IGSCC Program and will continue them during the period of extended

operation.

Also in its response to the staff's question, the applicant also stated that numerous UT

examinations of the nozzle blend radius prior to 2002 yielded no recordable or relevant

indications of degradation. The applicant has inspected the CRD return line nozzle-to-vessel

weld and the nozzle blend radius under the ISI Program in accordance with requirements of

ASME Code Section XI, Table IWB-2500-1, Code Category B-D, Item Nos. 83.90 and B3.100.

Additionally, the applicant has committed to continue enhanced visual examinations (EVT-ls)

(1⁄2A mil resolution) of the CRD return line nozzle blend radius and adjacent vessel wall area

during the fourth 10-year ISI interval as well as during the period of extended operation.

The staff finds the applicant's activities acceptable because the applicant appropriately followed

NUREG-0619 recommendations by cutting and capping the CRD return line nozzle in 1985 and

repaired the defect at the nozzle-to-cap weld with a structural weld overlay in 2000. Recent UT

examination of the nozzle-to-cap weld overlay in 2004 revealed no indications of cracking. In

addition, the EVT-1 visual inspection of the nozzle blend radius and adjacent vessel wall area in

2000 also revealed no cracking. Moreover, the applicant will continue ASME Code

examinations of the nozzle, including EVT-1 visual examination of the nozzle blend radius area,

during the period of extended operation.

The staff finds the applicant's BWR CRD Return Line Nozzle Program acceptable because it is

consistent with the recommended GALL AMP XI.M6, "BWR Control Rod Drive Return Line

Nozzle," with the following exceptions and enhancement:

Exception 1. The LRA states an exception to the GALL Report "scope" and "parameters

monitored or inspected" program elements, specifically:

The dissimilar weld between the CRDRL nozzle and end cap is not subject to ISI

per ASME Section XI, Subsection IWB.

The footnote to this exception states:

The dissimilar weld between the CRDRL nozzle and end cap is exempt from ISI

examination requirements per IWB-1 220(a). However, this weld is inspected by

UT as part of the JAFNPP IGSCC program. JAFNPP also employs HWC and

NMCA to mitigate the effects of IGSCC on the CRDRL nozzle.

The staff noted that, although the CRD return line meets ASME Code Section XI, IWB-1220(a)

requirements for exclusion from volumetric and surface examination, the applicant has

conducted volumetric UT examinations of the CRD return line nozzle-to-cap weld under its

IGSCC Inspection Program. The applicant initiated these inspections when it implemented

NUREG-0619 recommendations during the 1985 refueling outage. Inspections were scheduled

in accordance with BWRVIP-62 and BWRVIP-75-A. In 2000, UT examination of the weld

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revealed a defect on its inside wall and, after repairing the weld with a nickel-based Alloy 52

weld overlay, the applicant appropriately re-categorized the weld based on BWRVIP-75-A from

Category D to Category E. The staff verified that this weld is appropriately in the IGSCC

Program and that the nickel-based Alloy 52 in the weld overlay is resistant to IGSCC. The staff

also determined that the applicant employs hydrogen water chemistry (HWC) and noble metal

chemical addition (NMCA) to mitigate IGSCC effects. The staff finds that the applicant's

periodic inspection of the CRD return line nozzle-to-cap weld will detect any future defects in

the weld promptly. This inspection, along with the other activities to mitigate IGSCC, reasonably

assure maintenance of the structural and pressure boundary integrity of the reactor pressure

vessel (RPV) with the capped nozzle (N9) during the period of extended operation. On this

basis, the staff finds this exception acceptable.

Exception 2. The LRA states an exception to the GALL Report "preventive actions" program

element, specifically:

The flow capacity test required by NUREG-0619 was not performed prior to

capping the CRDRL nozzle.

The footnote to this exception states:

JAFNPP was granted an exemption from the requirement to perform a CRD

return flow capacity test per NUREG-0619 through an NRC letter (letter dated

August 25, 1983, from D. B. Vassallo [NRC] to J. P. Bayne [NYPA]) issued

before the CRDRL modification was made. JAFNPP is not required to perform

the flow capacity test, and successful system operation for more than 20 years

since the modification has confirmed proper return flow capability.

The staff reviewed the applicant's CRD return line modifications (JPN-83-64, CRD Return Line

Modifications (NUREG-0619), July 7, 1983) in response to NUREG-0619 and the associated

SER, and determined that the applicant had isolated the CRD return line in 1977 and

demonstrated satisfactory operation of the CRD system by a two-CRD pump capability test.

This test demonstrated that the flow rate of the isolated CRD return line was sufficient to heat

the vessel to normal pressure and temperature followed by a reactor scram as designed. When

the applicant requested approval to cap the CRD return line nozzle in 1983, the staff granted an

exemption from the flow capacity test required by NUREG-0619. As this test was not required

during the current period of operation, the staff finds it also not required during the period of

extended operation. On this basis, the staff finds this exception acceptable.

Exception 3. The LRA states an exception to the GALL Report "detection of aging effects" and

"monitoring and trending" program elements, specifically:

The extent and schedule of inspection, as delineated in NUREG-0619, are not

followed. Specifically, liquid penetrant testing (PT) of CRDRL nozzle blend

radius, adjacent wall area and bore regions is not performed.

The footnote to this exception states:

JAFNPP performs EVT-1 visual examinations (

1

1⁄2 mil resolution) of the CRDRL

nozzle blend radius and adjacent wall area every 10 years in lieu of PT

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examinations. The weld overlay installed over a crack in the CRD return line

nozzle-to-cap weld covers the nozzle, the nozzle-to-cap weld, and part of the

cap. The nickel-based Alloy 52 weld overlay, which is highly resistant to stress

corrosion cracking, is ultrasonically inspected in accordance with GL 88-01 and

BWRVIP-75-A. The weld overlay provides reasonable assurance of structural

and pressure boundary integrity of the RPV capped N9 nozzle and thus provides

an acceptable level of quality and safety. Since the nozzle and original

nozzle-to-cap weld are covered by the overlay, and the overlay is examined,

examination of the nozzle and originalnozzle-to-cap weld is not required.

The applicant's program basis document states that numerous UT examinations of the CRD

return line nozzle blend radius prior to 2002 yielded no recordable or relevant indications.

Enhanced visual examination (1⁄2 mil resolution) of the nozzle blend radius and adjacent vessel

wall area in 2000 also revealed no cracking. The applicant will continue its ISI, including the

EVT-1 visual examination, of the CRD return line nozzle blend radius and adjacent wall area

every ten years in lieu of penetrant testing (PT) examinations recommended in NUREG-0619.

The applicant's program basis document further states that the weld overlay installed over a

crack in the CRD return line nozzle-to-cap weld covers the nozzle, the nozzle-to-cap weld, and

part of the cap. The nickel-based Alloy 52 weld overlay is inspected ultrasonically under the

IGSCC Program. As the nozzle and original nozzle-to-cap weld are covered by the overlay, and

the overlay is examined, the applicant claimed that the examination of the nozzle and original

nozzle-to-cap weld is not required; however, the staff determined that the repair method for this

weld overlay (i.e., Code Case N-504-1(g)(2)) requires a design life for the weld. The applicant

has not demonstrated that the design life of the original nozzle-to-cap weld includes the period

of extended operation.

Although the aging management of the nozzle-to-cap weld and its overlay is acceptable, during

the audit and review the staff asked the applicant to justify not calculating (as a TLAA) the

design life of the original cracked weld.

In its response, the applicant stated that the modification required no such calculation for the

current operating term; moreover, weld overlays of this type maintain the original flaw in

compression and the qualifying evaluations assumed through-wall flaw growth to 360 degrees.

The staff determined that, as long as the structural integrity of the weld overlay maintains the

compressive load on it, the original weld flaw would not grow. The compressive force will

confine the flaw in its place. Moreover, periodic UT examination of the weld overlay verifies and

maintains its structural integrity during the period of extended operation; therefore, the weld

overlay reasonably assures the structural and pressure boundary integrity of the RPV capped

N9 nozzle.

Based on the above review, the staff determined that the current CRD Return Line Nozzle

Program, which includes IGSCC and NUREG-0619 requirements, reasonably assures

maintenance of the structural and pressure boundary integrity of the RPV with the capped CRD

return line nozzle; therefore, the staff determined that liquid PT of the CRD return line nozzle

blend radius, adjacent wall area, and bore regions is not required. On this basis, the staff finds

this exception acceptable.

Exception 4. The LRA states an exception to the GALL Report "acceptance criteria" program

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element, specifically:

JAFNPP repaired the CRDRL nozzle by weld overlay rather than removing the

crack by grinding and examines the overlay using UT in lieu of RT.

The footnote to this exception states:

In its letter of October 26, 2000, the NRC concluded that the proposed

alternative provides reasonable assurance of structural and pressure boundary

integrity of the RPV capped N9 nozzle and thus provides an acceptable level of

quality and safety. Therefore, pursuant to 10CFR 50.55a(a)(3)(I), the NRC staff

-authorized use of ASME Code Case N-504-1.

Based on the NRC letter dated October 26, 2000, the staff determined that use of a weld

overlay to repair the flawed RPV nozzle (N9) to the CRD return line cap weld was acceptable.

The staff determined that the initiation of the defect from the inside surface of the nozzle made

the code repair, which requires the removal of the defects from the flawed component by

grinding, impractical. Moreover, by use of a weld overlay, the repair could be completed without

draining the water from the reactor vessel and removing fuel from the core; therefore, at that

time, the staff approved the applicant's proposed repair of the flawed RPV nozzle (N9) to the

CRD return line cap weld by use of an overlay in accordance with ASME Code Cases N-504-1

and N-638 as an alternative to ASME Code Section Xl, IWB-4000 repair requirements. ASME

Code Case N-504-1 applies to austenitic weld overlays using Alloy 52 or Alloy 152 for local

repair. ASME Code Case N-638 applies to the use of an ambient temperature temper bead

welding technique.

The staff noted that the applicant examined the repaired weld by UT instead of a radiographic

test to verify the integrity of the newly-applied weld reinforcement. The applicant will continue

the UT examination of the weld overlay under the IGSCC Program. The staff finds UT

acceptable as a volumetric examination appropriatefor this type of weld. The UT examinations

will detect any weld flaws prior to the loss of any component intended function. The staff also

finds that the repair of the CRD return line nozzle-to-cap weld has been approved previously

and is an appropriate repair technique for this type of weld flaw. The repair reasonably assures

maintenance of RPV structural and pressure boundary integrity with the capped N9 nozzle. On

this basis, the staff finds this exception acceptable.

Enhancement. The LRA states an enhancement to the GALL Report "scope of program" and

"parameters monitored or inspected" program elements, specifically:

The CRD Return Line Nozzle Program will be enhanced to examine the CRDRL

nozzle-to-vessel weld and the CRDRL nozzle inside radius section per section Xl

Table IWB-2500-1 category B-D items B3.10 and B3.20.

During the audit and review, the staff noted that, in accordance with ASME Code Section XI,

Table IWB-2500-1, Code Category B-D, Item Nos. B3.90 and B3.100 (JAFNPP is an Inspection

Program B plant), the CRD return line nozzle-to-vessel weld and nozzle inside radius section

must have a volumetric examination during each ten-year ISI interval. The staff noted that the

LRA erroneously identifies these as Items B3.10 and B3.20, which are applicable for a

Program A plant.

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In its response dated February 1, 2007, the applicant amended LRA Section B.1.2 to state,

"Enhance the BWR CRD Return Line Nozzle Program to examine the CRDRL nozzle-to-vessel

weld and the CRDRL nozzle inside radius section per Section XI Table IWB-2500-1 Category

B-D Items B3.90 and B3.100" (Commitment No. 2) (JAFP-06-0109, dated July 31, 2006).

The staff also noted that inspection of the CRD return line nozzle-to-vessel weld and nozzle

inside radius section are ASME Code-required UT examinations (augmented by an EVT-1

examination in lieu of PT recommended in NUREG-0619) and asked the applicant, during the

audit and review, to explain why this inspection is an enhancement. The applicant explained

that at the time the LRA was written these inspections were not scheduled during the current

third ten-year ISI interval; however, the applicant later confirmed that these inspections have

been completed for the third ten-year ISI interval. The applicant also confirmed that it has

completed these inspections during the first and second ten-year ISI intervals and will continue

them during the fourth as well as during the period of extended operation.

The staff determined that the applicant meets ASME Code requirements for inspection of the

CRD return line nozzle-to-vessel weld and the CRD return line nozzle inside radius section and

will continue to meet them for the period of extended operation. On this basis, the staff finds

this enhancement acceptable.

Operating Experience. LRA Section B.1.2 states that on October 15, 2000, examination

revealed cracking of the CRD return line nozzle-to-cap weld. The probable cause was IGSCC

of the cap's susceptible base material (Inconel 600) and weld metal (Inconel 82/182). A

structural weld overlay was made with Inconel 52 weld metal, which is highly resistant to stress

corrosion cracking. The weld overlay process also imparts a compressive residual stress which

prevents further crack growth. The N9 nozzle-to-cap weld overlay received all code-required

preservice nondestructive examinations and was pressure-tested prior to service. Ultrasonic

examination of the nozzle-to-cap weld overlay in R016 (2004) revealed no indications of

cracking. Enhanced visual examination (1⁄2 mil resolution) of the nozzle blend radius and

adjacent vessel wall area in 2000 also revealed no cracking. As the weld overlay is highly

resistant to cracking and no indications of cracking have been observed, the BWR CRD Return

Line Nozzle Program remains effective for managing the effect of cracking on the intended

function of the CRD return line nozzle. A self-assessment in 2004 revealed no issues or

findings with impact on program effectiveness.

The staff reviewed past inspection results of the CRD return line nozzle since JAFNPP

implemented NUREG-0619 recommendations and confirmed that the results revealed no

indications of cracking in the nozzle-to-vessel and nozzle blend radius area. This is due to the

fact that the subject nozzle operated for only two years with the CRD return line in operation

before isolating it in 1977. In addition, the nozzle originally included a thermal sleeve which

protected the nozzle blend radius area.

The staff determined that JAFNPP cut and capped the CRD return line with an Inconel 600 cap

in 1985 and since then the dissimilar weld between the nozzle-to-cap was inspected as part of

the IGSCC Program. The inspections revealed no indications until 2000 when JAFNPP

detected a defect in the inside diameter of the weld due to IGSCC caused by the stagnant

reactor water within the capped nozzle. The applicant repaired the nozzle using a weld overlay.

Since then the inspections of the weld revealed no indications of cracking.

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The staff interviewed the applicant's technical staff and reviewed operating experience reports

and confirmed that the plant-specific operating experience did not include any effects of aging

for systems and components within the scope of this program that are not bounded by industry

operating experience. The.JAFNPP operating experience included detection of cracking in the

nozzle blend radius, the nozzle-to-vessel weld and the nozzle-to-cap weld. This effect of aging

is consistent with industry operating experience, and this AMP includes aging management

activities, such as UT and visual inspections that appropriately detect cracking. Corrective

actions were taken in accordance with the Plant Corrective Action Program prior to a loss of

intended function of the component.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10, The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.2, the applicant provided the UFSAR supplement for

the BWR CRD Return Line Nozzle Program. The staff reviewed the applicant's license renewal

commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and

confirmed that the enhancement for this program is identified as Commitment No. 2, which will

be implemented before the period of extended operation.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR CRD Return Line

Nozzle Program, the staff finds those program elements, for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions

and associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. Also, the staff reviewed the enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL AMP to which it was compared.

The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.3 BWR Feedwater Nozzle Program

Summary of Technical Information in the Application. LRA Section B.1.3 describes the existing

BWR Feedwater Nozzle Program as consistent, with exception, with GALL AMP XI.M5, "BWR

Feedwater Nozzle."

Under this program, the applicant has removed all identified feedwater blend radii flaws,

removed feedwater nozzle cladding, and installed a double piston ring and triple thermal sleeve

sparger to mitigate cracking. This program implements enhanced ISI of the feedwater nozzles

in accordance with ASME Section XI, Subsection IWB and the recommendation of General

Electric NE-523-A71-0594 to monitor the effects of cracking on the intended function of the

feedwater nozzles.

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Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the BWR Feedwater Nozzle

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M5.

LRA Section B.1.3 states that the applicant has removed all identified feedwater blend radii

flaws, removed feedwater nozzle cladding, and installed a double piston ring and triple thermal

sleeve sparger to mitigate cracking.

During the audit and review, the staff asked the applicant for additional information on the

activities performed to address the industry-wide feedwater nozzle cracking issues documented

in NUREG-0619.

In its response, the applicant stated that, although there were no indications noted during the

feedwater nozzle modification, JAFNPP removed stainless steel cladding at the feedwater

nozzle areas and installed the triple thermal sleeve and double piston-ring seal spargers to

meet the NUREG-0619 recommendations. The applicant also stated that the reference in LRA

Section B.1.3 to "removed all identified feedwater blend radii flaws" is not accurate since no

indications were noted during the nozzle modification.

In its letter dated February 1, 2007 (LRA Amendment 5), the applicant revised the LRA by

deleting "removed all identified feedwater blend radii flaws" from the program description

section of LRA Section B.1.30.

JAFNPP did not install new low-flow feedwater controllers or reroute the reactor water clean-up

(RWCU) system return flow at the time of feedwater nozzle modification. Re-routing of the

RWCU return flow to all feedwater lines is recommended in NUREG-0619 to improve system

performance and reduce temperature fluctuations at the nozzle bend areas during low-power

operation. Since then, inspections of the feedwater nozzle blend radius area have been

performed at every inspection interval in accordance with NUREG-0619 and General Electric

(GE) document NE-523-A71-0594 with no relevant and/or reportable indications.

The applicant also stated that the current JAFNPP Enhanced Inservice Inspection Program,

which addresses the augmented inspections in accordance NUREG-0619 and GE document

NE-523-A71-0594-A (Revision 1), expand the inner radius examination volume identified by

ASME Code Section XI to the nozzle outside diameter (OD) taper area. The staff also verified

that the last examination completed in 2002 using phased array automated techniques

(Wesdyne) revealed no indications in the feedwater nozzle inner radius area.

During the audit and review, the staff also asked the applicant to discuss how bypass flow

around the feedwater nozzle thermal sleeve is monitored, since this could occur due to a

degraded thermal sleeve seal.

In its response, the applicant stated that in the early nineties, JAFNPP eliminated the need to

perform a liquid penetrant test examination of the feedwater nozzles, as recommended by

NUREG-0619, and at the same time committed to utilize a leakage monitoring system (LMS) to

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monitor bypass flow across the thermal sleeve seal. However, in the third ten-year ISI period on

February 18, 1999 (JPN-99-003, Commitment Change - Feedwater Nozzle Leakage Monitoring

System, February 18, 1999), the applicant submitted to the staff a commitment change request

to discontinue the use of the LMS to monitor the bypass flow. The applicant provided the

technical basis for this commitment change, which stated that the temperature data from the

LMS had confirmed the effectiveness of the changes made to limit feedwater bypass flow. The

feedwater LMS, originally installed in 1992, measured the temperatures of the outside surface

of the feedwater nozzles downstream of the thermal sleeve seals. These temperatures were

then correlated to the secondary seal bypass leakage.

The applicant further stated that based on the evaluation of LMS data, secondary seal bypass

leakage was acceptable and no increasing trend hadý been exhibited by any of the four

feedwater nozzles. Moreover, the applicant is performing the feedwater nozzle examinations as

part of the Inservice Inspection Program, which includes augmented inspection activities per

GE-NE-523-A71-0594A. The staff found this acceptable, since the applicant has demonstrated

that the present feedwater nozzle triple thermal sleeves do not exhibit any bypass leakage and

the periodic inspection of the nozzle inner radius would ensure timely detection of any

developing defects in the nozzle blend radius area.

The staff found the applicant's activities acceptable, since the applicant appropriately followed

NUREG-0619 recommendations by removing clad material from the nozzle area and installed

an improved thermal sleeve sparger. Since then, UT examination of the feedwater nozzles

revealed no indications of cracking. Moreover, the applicant will continue Code inspections,

including augmented inspections per GE document NE-523-A71-0594-A and an expanded

inner radius examination volume to the nozzle OD taper area, during the period of extended

operation.

The staff finds the applicant's BWR Feedwater Nozzle Program acceptable because it

conforms with the recommended GALL AMP XI.M5, "BWR Feedwater Nozzle" Program with

the exception as described:

Exception. The LRA states an exception to the GALL Report program element "preventive

actions." Specifically, the exception states:

The reactor water cleanup system was not rerouted and a low flow controller

meeting all requirements of NEDO-21821-A was not installed.

The associated note to this exception states:

In its safety evaluation of JAFNPP actions taken to address feedwater nozzle

cracking, the NRC noted that the intent of the requirements of NUREG-0619 and

NED021821-A had been satisfied with the JAFNPP modifications. Since the

stainless steel cladding has been removed, the improved spargers have been

installed and the control rod drive return line has been cut and capped, an

adequate margin of safety against feedwater nozzle crack growth exists.

Therefore, NRC concluded that, with continued inspections to monitor for crack

initiation and growth, JAFNPP can operate without rerouting the RWCU and

without installing a low-flow controller for the feedwater system. Since

inspections to monitor for crack initiation and growth will continue per ASME

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Section XI, this conclusion remains valid for the period of extended operation.

The staff finds this exception acceptable since the current JAFNPP BWR Feedwater Nozzle

Program includes recommendations in NUREG-0619, with the exception that the applicant has

not installed low-flow controllers or re-routed the RWCU return lines to the feedwater system.

This exception has been approved by the staff and is the CLB for JAFNPP. Also, since

inspections to monitor for crack initiation and growth will continue per ASME Code Section XI,

this conclusion remains valid for the period of extended operation.

Operatincq Experience. LRA Section B.1.3 states that ultrasonic testing of the feedwater nozzles

during RO1 5 (2002) recorded no indications. Absence of recordable indications on the

feedwater nozzles proves that the program is effective for managing nozzle cracking. As stated

in GALL Report Section XI.M5, "The present AMP has been implemented for nearly 20 years

and found to be effective in managing the effect of cracking on the intended function of

feedwater nozzles." Recent inspections recorded no indications, thus the program is effective in

managing the effect of cracking on the intended function of the feedwater nozzles. A

self-assessment in 2004 revealed no issues or findings with impact on program effectiveness.

The staff reviewed past inspection results of the feedwater nozzle and determined that the initial

PT examinations followed by the UT examination of the nozzle area during later years revealed

no indications in the feedwater nozzle inner radius area at JAFNPP. There were no reportable

defects in its feedwater nozzles when JAFNPP implemented NUREG-0619 recommendations.

The staff also verified that the last examination completed in 2002 using phased array

automated techniques (Wesdyne) revealed no indications in the feedwater nozzle inner radius

area. The staff reviewed the 2004 self-assessment report which revealed no issues or findings

with impact on the effectiveness of this program.

The staff interviewed the technical staff and also reviewed operating experience reports and

confirmed that the plant-specific operating experience did not include any effects of aging for

systems and components within the scope of this program that are not bounded by industry

operating experience. This effect of aging is consistent with industry operating experience, and

this AMP includes aging management activities, such as UT examination, appropriate to detect

cracking. Corrective actions were taken in accordance with the Plant Corrective Action Program

prior to a loss of intended function of the component.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.3, the applicant provided the UFSAR supplement for

the BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR Feedwater Nozzle

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and the

associated justifications, and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant has

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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).

3.0.3.2.4 BWR Penetrations Program

Summary of Technical Information in the Application. LRA Section B.1.4 describes the existing

BWR Penetrations Program as consistent, with exception, with GALL AMP XI.M8, "BWR

Penetrations Program."

The program includes: (a) inspection and flaw evaluation in accordance with the guidelines of

staff-approved boiling water reactor vessel and internals project (BWRVIP) documents

BWRVIP-27-A and BWRVIP-49-A and (b) monitoring and control of reactor coolant water

chemistry in accordance with BWRVIP-130 guidelines to ensure the long-term integrity of

vessel penetrations and nozzles.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the BWR Penetrations

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M8.

The applicant stated that for the JAFNPP instrument penetration configuration, BWRVIP-49-A

recommended no additional inspections beyond those required by ASME Code Section XI,

Subsection IWB-2500. JAFNPP performs ISIs to monitor the effects of cracking on the intended

function of the instrument penetrations in accordance with ASME Code Section XI, Subsection

IWB. Visual VT-2 inspections of instrument nozzle partial penetration and nozzle-to-extension

welds are performed during system pressure testing (Code Item B4.13). The nozzle forging and

the nozzle inner radius are exempt from volumetric examination in accordance with ASME Code

Section XI, Subsection IWB-1220(c).

The applicant also stated that for the JAFNPP standby liquid control (SLC) nozzle configuration,

BWRVIP-27-A recommends, in addition to the requirements of ASME Code Section XI,

Subsection IWB, a volumetric examination of the nozzle-to-safe-end connection weld be

performed every 10 years, as soon as a method for conducting that examination is developed.

In accordance with this BWRVIP-27-A recommendation, JAFNPP performs an enhanced visual

leakage VT-2 inspection (with direct view of the component during pressure test) every outage

and a surface examination every 10 years. This will be continued until a volumetric inspection

technique is developed. Once an acceptable volumetric examination is developed, it will be

performed each 10 year ISI interval in conjunction with continued visual inspections each

outage. JAFNPP performs ISIs to monitor the effects of cracking on the intended function of the

SLC/deltaP (AP) penetration in accordance with ASME Code Section XI, Subsection IWB,

during system pressure testing.

The staff noted that LRA action Item 4 in BWRVIP-27-A states that due to the susceptibility of

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SLC/AP penetrations to fatigue, applicants referencing the BWRVIP-27 report for license

renewal should identify and evaluate the projected fatigue cumulative usage factors as a

potential TLAA issue. In LRA Appendix.C, the applicant stated that this fatigue analysis is

required only for the low-alloy steel. nozzle designs. The applicant further stated that the

JAFNPP SLC/AP nozzle is an SB-166 nickel-based alloy insert; therefore, this action item is not

applicable to JAFNPP.

The staff reviewed the BWRVIP recommendations associated with this program and

determined that the applicant's activities are consistent with these recommendations. The staff

also determined that the applicant's program provides timely detection of any defects in the

instrument and SLC/AP nozzle penetrations. Based on this, the staff finds the applicant's

activities acceptable.

The staff finds the applicant's BWR Penetrations Program acceptable because it is consistent

with the recommended GALL AMP XI.M8, "BWR Penetrations Program," with the exception as

described:

Exception. The LRA states an exception to the GALL Report program elements "parameters

monitored/inspected," and "detection of aging effects." Specifically, the exception states:

Table IWB-2500-1 from the 1989 edition of ASME Section Xl is used, while

NUREG-1 801 specifies the 2001 edition with 2002 and 2003 addenda.

The associated note to this exception states:

Since ASME Section XI editions through the 2003 Addenda have been accepted

by reference in 10CFR50.55a(b) (2) without modification or limitation on use of

Table IWB-2500-1 from the 1989 edition for BWR components, use of this

version is appropriate to assure that components crediting this program can

perform their intended function consistent with the current licensing basis during

the period of extended operation.

As indicated in LRA Amendment No. 5 dated February 1, 2007, the 4' 10-Year ISI Interval for

JAFNPP will be the 10-Year ISI interval in effect if the LRA is approved by the staff. The

applicant's amendment of the LRA is in compliance with the requirements of 10 CFR 50.55a

because the applicant was required by paragraph (b) of the rule to update in Section XI edition

of reference to 2001 Edition of Section XI (inclusive of the 2003 Addenda), one year prior to

entering the 4h 10-Year ISI Interval for JAFNPP. Based on this assessment, the staff concludes

that the changes to the LRA are acceptable because they are in compliance with the

requirements of 10 CFR 50.55a and in conformance (i.e., consistent) with the "scope of

program" element in GALL AMP XI.M8, "BWR Penetrations."

The staff evaluated this exception as part of its review of the Inservice Inspection Program and

finds it acceptable, since it is consistent with the requirements of 10 CFR 50.55a. The staff's

evaluation is discussed in SER Section 3.0.3.3.3.

Operatingq Experience. LRA Section B.1.4 states that visual examination of the standby liquid

control nozzle during the reactor vessel system leakage tests in the last three outages (2000,

2002, and 2004) recorded no indications or leakage. Visual examination of the instrument

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penetration nozzles during the reactor vessel system leakage tests in the last three outages

(2000, 2002, and 2004) recorded no indications or leakage. Absence of recordable indications

on the standby liquid control and instrument penetration nozzles proves that the program is

effective for managing cracking of the nozzles. Self-assessments in 2004 and 2005 revealed no

issues or findings that would impact program effectiveness.

The staff also reviewed the operating experience reports and confirmed that the plant-specific

operating experience did not include any effects of aging for systems and components within

the scope of this program that are not bounded by industry operating experience. The JAFNPP

operating experience included detection of cracking in the SLC/AP nozzle (N10) and instrument

nozzles (N11, N12 and N16). This effect of aging is consistent with industry operating

experience, and this AMPincludes aging management activities, such as visual inspections and

surface examinations appropriate to detect cracking. The staff found no indications or leakage

during pressure testing in the past inspections (2000, 2002, and 2004) and found the program

effective in mitigating any cracking prior to a loss of intended function of these nozzles.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.4, the applicant provided the UFSAR supplement for

the BWR Penetrations Program. The staff determines that the information in the UFSAR

supplement provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR Penetrations Program,

the staff finds that those program elements, for which the applicant claimed consistency with

the GALL Report are consistent. In addition, the staff reviewed the exception and the

associated justifications, and determined that the AMP, with the exception, is adequate to

manage the aging effects forwhich it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.5 BWR Stress Corrosion Cracking Program

Summary of Technical Information in the Application. LRA Section B. 1.5 describes the existing

BWR Stress Corrosion Cracking Program as consistent, with exception, with GALL AMP XI.M7,

"BWR Stress Corrosion Cracking Program."

The program includes: (a) preventive measures to mitigate IGSCC and (b) inspection and flaw

evaluation to monitor IGSCC and its effects on reactor coolant pressure boundary components

made of stainless steel or cast austenitic stainless steel. The applicant has taken actions to

prevent IGSCC and will continue to use materials resistant to IGSCC for component

replacements and repairs following the recommendations of NUREG-0313, Generic Letter

(GL) 88-01, and the staff-approved BWRVIP-75-A report. Inspection of piping identified in

GL 88-01 to detect and measure cracks is in accordance with the staff positions on schedule,

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method, personnel qualification, and sample expansion included in the generic letter and the

staff-approved BWRVIP-75-A report.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the BWR Stress Corrosion

Cracking Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M7.

The applicant stated that the BWR Stress Corrosion Cracking Program will be implemented in

accordance with BWRVIP-75-A guidelines for "parameters monitored/inspected," "detection of

aging effects," "monitoring and trending," and "acceptance criteria." The BWRVIP guidelines

require an expanded inspection scope, and re-inspection if flaws are detected.

During the audit and review, the staff asked the applicant for additional information on all weld

repairs and material replacement of components that occurred when implementing

NUREG-0313 and GL 88-01 recommendations.

In its response, the applicant stated that the following piping was replaced with IGSCC resistant

material (low carbon stainless steel): (a) the core spray piping from the RPV nozzle on B-loop to

the first isolation valve was replaced with 347NG in 1992, and (b) the core spray A-loop was

replaced from the safe-end to the isolation valve with 316L. All other IGSCC welds were

repaired using weld overlays. Pipe specification Class 1504 was modified for future

procurement to restrict carbon content to 0.035% maximum, ferrite to 8% minimum in weld

metal and to require solution annealing.

The applicant further stated in their response that the overlays were installed and designed in

accordance with GL 88-01, NUREG-0313, Revision 2, and ASME Code requirements. The

post-weld overlay examinations performed on these welds revealed no reportable and/or

unacceptable indications. The staff verified that the applicant has fully implemented the

GL 88-01 and NUREG-0313 guidelines and has been inspecting the relevant piping in

accordance with NRC-approved BWRVIP-75-A, since the BWR Stress Corrosion Cracking

Program was first implemented.

The staff found that the applicant appropriately mitigated IGSCC in systems and components

by implementing the requirements of GL 88-01, NUREG-0313 and BWRVIP-75-A, and is

following the requirements of the ASME Code version currently applicable to JAFNPP. Since

the BWRVIP guidelines for reactor vessel internal components requires an expanded inspection

scope and re-inspection if flaws are detected, the added requirements provide additional

assurance that the inspection program offers timely detection of future defects. On this basis,

the staff finds this planned modification acceptable.

The staff finds the applicant's BWR Stress Corrosion Cracking Program acceptable because it

is consistent with the recommended GALL AMP XI.M7, "BWR Stress Corrosion Cracking

Program," with the exception as described below.

Exception. The LRA states an exception to the GALL Report program element "acceptance

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criteria." Specifically, the exception states:

The 1989 edition of ASME Section XI is used for flaw evaluation, while NUREG1801 specifies the 1986 edition.

The associated note to this exception states:

ASME Section XI 1989 edition has been accepted by the NRC in 10 CFR

50.55a(b)(2) without modification or limitation on use of this edition for flaw

evaluation. Thus, components crediting this program can be expected to perform

their intended function consistent with the current licensing basis during the

period of extended operation.

As indicated in LRA Amendment No. 5 dated February 1, 2007, the 4th 10-Year ISI Interval for

JAFNPP will be the 10-Year ISI interval in effect if the LRA is approved by the staff. The

applicant's amendment of the LRA is in compliance with the requirements of 10 CFR 50.55a

because the applicant was required by paragraph (b) of the rule to update in Section XI edition

of reference to 2001 Edition of Section XI (inclusive of the 2003 Addenda), one year prior to

entering the 4t 10-Year ISI Interval for JAFNPP. Based on this assessment, the staff concludes

that the changes to the LRA are acceptable because they are in compliance with the

requirements of 10 CFR 50.55a and in conformance (i.e., consistent) with the "scope of

program" element in GALL AMP XI.M7, "BWR Stress Corrosion Cracking."

The staff evaluated this exception as part of its review of the Inservice Inspection Program, and

finds it acceptable, since it is consistent with the requirements of 10 CFR 50.55a. The staffs

evaluation is discussed in SER Section 3.0.3.3.3.

Operating Experience. LRA Section B. 1.5 states that ultrasonic examinations of four

recirculation nozzle safe-end welds, three jet pump instrumentation nozzle safe-end welds,

seven recirculation system piping welds, and three residual heat removal (RHR) system piping

welds during RO15 (2002) recorded six indications attributed to geometric conditions and not

cracks. Ultrasonic examinations of the CRD nozzle-to-cap weld overlay and three recirculation

system piping welds during R016 (2004) recorded one indication attributed to geometric

conditions and not a crack. Absence of cracks on the nozzle and piping welds proves that the

program is effective for managing cracking of austenitic stainless steel components.

In LRA Section B.1.5, the applicant stated that UT examination of four recirculation nozzle

safe-end welds, three jet pump instrumentation nozzle safe-end welds, seven recirculation

system piping welds, and three RHR system piping welds during RO 15 (2002) resulted in six

indications attributed to geometric conditions and not cracks.

During the audit and review, the staff asked the applicant to clarify these recently recorded six

indications attributed to geometry.

In its response, the applicant stated that performance demonstration initiatives (PDI)s personnel

performed the examinations in accordance with Washington Group procedure JAF-UT-89-1,

"Manual Ultrasonic Examination Austenitic and Dissimilar Metal Piping Welds," Revision 0. The

examinations adopted the PDI requirements of ASME Code Procedure PDI-UT-2 (at the time)

for piping welds, as required by 10 CFR 50.55a. The examinations identified geometry which

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required recording to comply with JAF-UT-89-1 procedures. The root and counterbore

geometry identified was recorded and evaluated by the examiner consistent with procedural

requirements and techniques developed during the PDI. PDI procedures provide guidance for

the evaluation of indications observed during examinations. The evaluation criterion is applied

by PDI qualified examiners as necessary indication evaluation and varies depending upon the

examination and circumstances encountered. The applicant also stated that the discussion in

the LRA with regard to the number of welds inspected is incorrect and will be corrected.

In its letter dated February 1, 2007 (LRA Amendment 5), the applicant revised LRA

Section B.1.5 to state:

The operating experience section is revised to state as follows: 'Ultrasonic

examination of four recirculation nozzle safe-end welds, one jet pump

instrumentation nozzle safe-end weld and two piping welds (Note that N8-SE-1

and N8-SE-3 welds are piping welds despite nomenclature), seven recirculation

system piping welds, and five RHR system piping welds.'

The staff found that the six recorded indications in 2002 (and one indication in 2004) evaluated

by the PDI-trained examiners in accordance with procedures developed during the PDI are

attributed to the root and counterbore geometry of the weld rather than cracks. Therefore, the

staff finds that the applicant has appropriately stated that the UT examinations performed

during 2002 and 2004 revealed no cracks in the systems as identified in the operating

experience in LRA Section B.1.5.

The staff also reviewed operating experience reports and confirmed that the plant-specific

operating experience did not include any effects of aging for systems and components within

the scope of this program that are not bounded by industry operating experience. The JAFNPP

operating experience included detection of cracking due to IGSCC in stainless steel and CASS

components. This effect of aging is consistent with industry operating experience and this AMP

includes aging management activities, such as UT and leakage, appropriate to detect cracking.

Corrective actions were taken in accordance with the Plant Corrective Action Program prior to a

loss of intended function of these components.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.5, the applicant provided the UFSAR supplement for

the BWR Stress Corrosion Cracking Program. The staff determines that the information in the

UFSAR supplement provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR Stress Corrosion

Cracking 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 the associated justifications and determined that the AMP, with the exception, is

adequate to manage the aging effects for which it is credited. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

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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).

3.0.3.2.6 BWR Vessel ID Attachment Welds Program

Summary of Technical Information in the Application. LRA Section B.1.6 describes the existing

BWR Vessel ID Attachment Welds Program as consistent, with an exception, with GALL

AMP XI.M4, "BWR Vessel ID Attachment Welds."

The program includes: (a) inspection and flaw evaluation in accordance with the guidelines of

the staff-approved -BWRVIP-48-A report and (b) monitoring and control of reactor coolant water

chemistry in accordance with the guidelines of BWRVIP-130 (EPRI Report 1008192) to ensure

the long-term integrity and safe operation of reactor vessel inside diameter (ID) attachment

welds and support pads.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the BWR Vessel ID

Attachment Welds Program bases documents. Specifically, the staff reviewed the program

elements and associated bases documents to determine consistency with GALL AMP XI.M4.

During the audit and review, the staff asked the applicant to clarify whether the BWR Vessel ID

Attachment Welds Program implements the evaluation guidelines of BWRVIP-14, "Evaluation

of Crack Growth in BWR Stainless Steel RPV Internals," BWRVIP-59, "Evaluation of Crack

Growth in BWR Nickel Base Austenitic Alloys in RPV Internals," and BWRVIP-60, "Evaluation

of Crack Growth in BWR Low Alloy Steel RPV Material," as recommended in GALL AMP XI.M4.

In its response, the applicant stated that crack growth indications found during reactor vessel

internals inspection are documented, evaluated and reported in accordance with these

BWRVIP guidelines and the applicable code for the indication. The staff determined that this is

acceptable because it is consistent with GALL recommendations.

The staff finds the applicants BWR Vessel ID Attachment Welds Program acceptable because

it conforms to the recommended GALL AMP XI.M4, "BWR Vessel ID Attachment Welds"

Program with the exception described below.

Exception. The LRA states an exception to the GALL Report program element "parameters

monitored/inspected." Specifically, the exception states:

Table IWB-2500-1 from the 1989 edition of the ASME Section XI is used while

NUREG-1801 specifies the 2001 edition with 2002 and 2003 addenda.

The associated note to this exception states:

1. Since ASME Section XI editions through the 2003 Addenda have been

accepted by reference in § 50.55a(b)(2) without modification or limitation on use

of Table IWB-2500-1 from the 1989 edition for BWR components, use of this

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version is appropriate to assure that components crediting this program can

perform their intended function consistent with the current licencing basis during

the period of extended operation. The JAF plant has also submitted a relief

request to use BWRVIP inspections, for the most part, in lieu of ASME XI.

As indicated in LRA Amendment No. 5 dated February 1, 2007, the 4h 10-Year ISI Interval for

JAFNPP will be the 10-Year ISI interval in effect if the LRA is approved by the staff. The

applicant's amendment of the LRA is in compliance with the requirements of 10 CFR 50.55a

because the applicant was required by paragraph (b) of the rule to update in Section XI edition

of reference to 2001 Edition of Section XI (inclusive of the 2003 Addenda), one year prior to

entering the 4 th 10-Year ISI Interval for JAFNPP. Based on this assessment, the staff concludes

that the changes to the LRA are acceptable because they are in compliance with the

requirements of 10 CFR 50.55a and in conformance (i.e., consistent) with the "scope of

program" element in GALL AMP XI.M4, "BWR Vessel ID Attachment Welds."

The staff finds this exception acceptable because the applicable code for the fourth ten-year ISI

interval is the 2001 edition of ASME Code Section XI, inclusive of the 2003 Addenda.

Operating Experience. LRA Section B.1.6 states that the following visual examinations of vessel

ID attachment welds have been conducted: core spray brackets examined during RO13 (1998)

and jet pump riser brace attachments examined 50 percent during RO1 1 (1994) and 50 percent

during R013. These examinations recorded no indications. Visual and enhanced visual

examinations of vessel ID attachment welds during RO1 5 (2002) and RO1 6 (2004) recorded no

indications. Absence of recordable indications on the vessel attachment welds proves that the

program is effective for managing cracking of the welds. As stated in GALL Report,

Section XI.M4, "Implementation of the program provides reasonable assurance that crack

initiation and growth will be adequately managed and the intended functions of the vessel ID

attachments will be maintained consistently with the CLB for the period of extended operation."

The program is consistent with the GALL Report program and recent inspection results

recorded no indications, thus, the program is effective in managing the effect of cracking on the

intended function of the vessel ID attachments. Self-assessments in 2004 and 2005 revealed

no issues or findings with impact on program effectiveness.

The staff interviewed the applicant's technical staff and also reviewed the operating experience

reports and confirmed that the plant-specific operating experience did not reveal any

degradation not bounded by industry operating experience.

In addition, the staff reviewed condition reports for the BWR Vessel ID Attachment Welds

Program and did not find any evidence of JAFNPP component degradation or failure outside

the envelope of industry experience.

The staff noted that in 2005, a self assessment identified that the applicant's BWRVIP Program

was not in compliance with all BWRVIP recommendations. One of the recommendations was to

make the BWRVIP Program consistent with BWRVIP recommendations.

During the audit and review, the staff asked the applicant if all the recommendations identified

in the corrective action were incorporated in the BWRVIP Program. The applicant confirmed

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that all recommendations resulting from the BWRVIP self assessment were completed at the

end of JAFNPP RO1 7. The staff confirmed that program deficiencies were identified and

resolved through the Corrective Action Program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.6, the applicant provided the UFSAR supplement for

the BWR Vessel ID Attachment Welds Program. The staff determines that the information in

the UFSAR supplement provides an adequate summary description of the program, as required

by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR Vessel ID Attachment

Welds Program, the staff finds those program elements, for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception

and the associated justifications, and determined that the AMP, with the exception, is adequate

to manage the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.7 BWR Vessel Internals Program

Summary of Technical Information in the Application. LRA Section B.1.7 describes the existing

BWR Vessel Internals Program as consistent, with exceptions, with GALL AMP XI.M9, "BWR

Vessel Internals."

The program includes (a)-inspection, flaw evaluation, and repair in conformance with the

applicable, staff-approved BWRVIP documents and (b) monitoring and control of reactor

coolant water chemistry in accordance with the guidelines of BWRVIP-130 to ensure the

long-term integrity of vessel internal components.

Staff Evaluation. During its audit and review, the staff reviewed the exceptions to determine

whether the AMP, with the exceptions, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the BWR Vessel Internals

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M9. The GALL

AMP XI.M9 recommends that applicants implement the augmented inspection and flaw

evaluation guidelines of the Boiling Water Reactor Vessel and Internals Program for their

reactor vessel and reactor vessel internal components.

Topical Report BWRVIP-94, "BWR Vessel and Internals Project Program Implementation

Guide,"establishes the BWRVIP's recommended guidelines for implementing the augmented

inspection, mitigation, and/or flaw evaluation activities provided in the other BWRVIP guideline

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documents.

During the audit and review, the staff asked the applicant to identify the BWRVIP guidelines

that are within the scope of BWR Vessel Internals Program and to clarify whether the

implementation guidelines of BWRVIP-94 are within the scope of this AMP.

In its response, the applicant clarified that the BWR Vessel Internals Program is based on

GALL AMP XI.M9 and that the scope of the program includes the BWRVIP inspection and flaw

evaluation guidelines specified in GALL AMP XI.M9. The applicant also stated that BWRVIP-94

provides the BWRVIP's guidelines for implementing the BWRVIP reports applicable to JAFNPP

and the Entergy Nuclear North (ENN) Procedure ENN-DC-135 requires that the implementation

guidelines in BWRVIP-94 be implemented as part of the program. The audit team reviewed

Procedure ENN-DC-1 35 and confirmed that the implementation guidelines in BWRVIP-94 are

invoked by the implementation procedure. Based on this assessment, the audit team concludes

that the implementation guidelines of BWRVIP-94 are within the scope of the applicant's BWR

Vessel Internals program.

The staff finds the applicant's BWR Vessel Internals Program acceptable because it is

consistent with the recommended GALL AMP XI.M9, "BWR Vessel Internals," with the

exceptions as described:

The applicant identified that the BWR Vessel Internals Program includes five exceptions to the

staff position taken in GALL AMP XI.M9. The staff summarizes and evaluates these exceptions

in the five paragraphs that follow.

Exception 1. The LRA states an exception to the GALL Report program elements "scope of

program," and "detection of aging effects." Specifically, the exception states:

Core Plate: JAFNPP provides an alternate inspection for the core plate rim

hold-down bolts that is technically justified according to BWRVIP-94.

The core plate design at JAFNPP does not rely on core plate wedges or plugs to maintain the

structural integrity of the plates during normal operations of the plant (including anticipated

operation transients and startup and cooldown operations), pressure test conditions, or

postulated design basis accident conditions. Instead, the integrity of the plates during these

conditions is maintained by the rim hold-down bolts.

The BWRVIP's augmented inspection and flaw evaluation criteria for BWR core support plates

are provided in Topical Report BWRVIP-25, which was approved by the staff in an safety

evaluation (SE) dated December 7, 2000. The staff informed the applicant that Topical Report

BWRVIP-94 provides the BWRVIP's implementation guidelines and does not provide a

BWRVIP-recommended inspection and flaw evaluation strategy for particular BWR vessel

internal components.

During the audit and review, the staff asked the applicant to provide the basis for deviating from

augmented inspection and flaw evaluation criteria provided in Topical Report No. BWRVIP-25.

Also, the applicant was asked to clarify why it is acceptable to use BWRVIP-94 as the basis for

taking this exception when Topical Report BWRVIP-94 is the only implementation guideline

document.

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The applicant stated that the BWRVIP's recommended methods for performing augmented

examinations of the rim hold-down bolts are not feasible for the design and configuration of the

rim hold-down bolts at JAFNPP. Because of this issue, the applicant developed technical

justifications to deviate from the inspection guidelines of BWRVIP-25 for the augmented

examinations of the core plate rim hold-down bolts. The applicant also stated that these

justifications were submitted to the staff in accordance with BWRVIP-94 guidelines.

BWRVIP-25 recommends implementation of specific augmented volumetric or visual

inspections options for BWR core plates that are secured solely with rim hold-down bolts (i.e.,

core plates that are not designed with wedges or plugs for structural integrity), or alternatively,

that the designs of the core plates be modified to include wedges as the basis for maintaining

the structural integrity of core plate against lateral movement. The staff determined that the

current basis for inspecting the core plate rim hold-down bolts at JAFNPP relies solely on

inspections performed in accordance with ASME Code Section Xl, Table IWB-2500-1, B-N-1

requirements. These requirements call for the applicant to implement a VT-3 visual examination

of the accessible surfaces of the core plate. The staff concluded that the current basis for

examining the core plate would not be sufficient to manage either stress relaxation or cracking

of the core plate rim hold-down bolts during the period of extended operation.

In its letter dated April 6, 2007, the applicant committed (Commitment No. 23 (JAFP-07-0019

dated February 1, 2007)) to take the following actions to ensure the structural integrity of the

JAFNPP core plate against lateral movement during the period of extended operation.

1. Install core plate wedges prior to the PEO, or,

2. Complete a plant-specific analysis to determine acceptance criteria for

continued inspection of the core plate rim hold down bolting in

accordance with BWRVIP-25, and submit the inspection plan, along with

the acceptance criteria and justification for the inspection plan, to the

NRC two years prior to the PEO for NRC review and approval.

If Option 2 is selected, the analysis to determine acceptance criteria will address

the information requested in RAIs 3.1.2-2A and 4.7.3.2-1.

Under the current design, the core plate rim hold-down bolts serve as the structural

components that maintain the integrity of the core plate against lateral movement. If option 1 of

Commitment No. 23 is selected, the installation of core plate wedges will replace the core plate

rim hold-down bolts as the basis for maintaining the structural integrity of the core plate against

lateral movement during the period of extended operation. This is in accordance with the

options provided in BWRVIP-25 and the staff finds this acceptable. If option 2 is selected, the

applicant will: (1) perform a plant-specific analysis in accordance with bolt loading analysis

criteria in BWRVIP-25, to establish the number of core plate rim hold-down bolts necessary to

maintain the structural integrity of the plant's core plate against lateral movement, and (2)

submit an inspection plan for the core plate rim hold-down bolts along with the technical basis

for the inspection plan for staff review and approval. This is acceptable because the staff has

approved the BWRVIP's criteria for performing plant-specific loading analyses of BWR core

plate rim hold-down bolts in the staff's SER dated December 7, 2000, and the inspection plan

for the core plate rim hold-down bolts will be submitted to the staff for review and approval at

least two years prior to entering the period of extended operation.

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The staff determined that this exception is acceptable because the alternative basis in LRA

Commitment No. 23 is consistent with the staff's conclusions reached in the staff's BWRVIP-25

SER dated December 7, 2000.

Exception 2. The LRA states an exception to the GALL Report program elements "scope of

program," and "detection of aging effects." Specifically, the exception states, "Shroud Support:

Focused inspection of bottom surface of the shroud support H9 weld."

The applicant's footnote on this exception identified that the focused examination of the H9

weld will be performed in accordance with applicable BWRVIP guidelines.

The BWRVIP's augmented inspection and flaw evaluation criteria for BWR core shroud

supports are provided in Topical Report BWRVIP-38, approved by the staff in a SE dated

March 1, 2001.

During the audit and review, the staff asked the applicant to confirm if Entergy is referring to the

inspection criteria for shroud support structures in Topical Report BWRVIP-38.

In its response, the applicant stated that it would implement the inspections of the JAFNPP core

shroud support in accordance with the recommended guideline of Topical Report BWRVIP-38.

The staff approved the augmented methods for inspecting core shroud supports and

attachments in an SE on Topical BWRVIP-38 dated March 1, 2001. The applicant's methods

for performing the augmented examinations of the JAFNPP core shroud support and its

attachments are acceptable because the applicant will use the methods of inspection proposed

in Topical Report BWRVIP-38 and approved by the staff in the SE dated March 1, 2001.

On this basis, the staff concludes that the applicant's proposal to perform a focused

examination of the shroud support H9 weld in accordance with BWRVIP-38 examination criteria

is acceptable.

Exception 3. The LRA states an exception to the GALL Report program elements "scope of

program," and "detection of aging effects." Specifically, the exception states:

Top Guide: Deferred inspection of hold-down Assemblies at 00 and 1800 from RO16 to

RO1 7 with technical justification. The top guide rim weld does not exist at JAFNPP and

is therefore exempt.

The applicant also identified that JAFNPP top guide design does not include a rim weld and

stated that the top guide is exempt from the augmented inspection criteria in BWRVIP-26 for

top guide rim hold-down welds.

The BWRVIP's augmented inspection and flaw evaluation criteria for BWR top guides are

provided in Topical Report BWRVIP-26 and approved by the staff in an SE dated

December 7, 2000. The staff concluded that the JAFNPP top guide design provides an

acceptable basis for exempting the top guide from the inspection criteria in BWRVIP-26 for top

guide rim welds because the weld does not exist in the design.

During the audit and review, the applicant informed the staff that the deferral of the inspection

of the top guide hold-down assemblies at the 0 °and 180 0 azimuthal locations from R016 to

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RO1 7 was based on a management decision. The applicant clarified that Entergy has been

performing the BWRVIP-26-A inspections of the top guide hold-down assemblies in spite of the

"lift off" analysis in Topical Report BWRVIP-26-A that demonstrates that the JAFNPP top guide

will not lift under the vertical loads associated with the limiting seismic event (i.e., under the

vertical loads associated with the postulated faulted conditions for the plant). The staff

concludes that a deferral of one RO for performing the inspections of the top guide hold-down

assemblies is a decision that is limited to the current licensed operating period for JAFNPP and

that the deferral of the top guide hold-down assemblies examinations from R016 to R017 will

not impact the applicant's schedule for inspecting these locations during the period of extended

operation. On this basis, the staff concludes that this exception is acceptable.

During the audit and review, the staff asked the applicant whether the augmented inspections

of the top guide grid beam locations would conform to the recommendations in GALL

AMP XI.M9 for top guide grid beam locations. GALL AMP XI.M9 established the position that

for BWR top guides with neutron fluences exceeding a fluence of 5 x 1020 n/cm2 (E > 1.0 MeV),

the BWR plants should perform EVT-1 examinations of a total of five percent of the top guide

grid beam locations within six years of entering the period of extended operation, and an

additional five percent of the top guide cross hatch areas within 12 years of entering the period

of extended operation. The staff also asked the applicant to provide a technical justification that

clarifies how the program basis in the commitment is considered sufficient to manage

irradiation-assisted stress corrosion cracking (IASCC) in the top guide for the period of

extended operation years 12 through 20.

In its response, the applicant provided Commitment No. 21 (JAFP-06-0167, dated

December 6, 2006) on the LRA to address augmented inspections of the JAFNPP top guide

grid beam locations for the period of extended operation. In Commitment No. 21 letter dated

April 6, 2007, Entergy committed to performing the following augmented inspections of the

JAFNPP top guide grid beam locations:

Enhance the BWR Vessel Internals Program to inspect fifteen (15) percent of the

top guide locations using enhanced visual inspection techniques. EVT-1, within

the first 18 years of the period of extended operation, with at least one-third of

the inspections to be completed within the first six (6) years and at least

two-thirds within the first 12 years of the period of extended operations.

Locations selected for examination will be areas that have exceeded the neutron

fluence threshold.

GALL AMP XI.M9 recommends that BWR applicants perform EVT-1 examinations of five

percent of their top guide grid beam locations with six years of entering the period of extended

operation and an addition five percent of the grid beam locations within 12 years of entering the

period of extended operation. The staff determined that LRA Commitment No. 21 is more

conservative than the criteria specified in GALL AMP XI.M9 and is acceptable.

Exception 4. The LRA states an exception to the GALL Report program elements "Scope of

Program," and "Detection of Aging Effects." Specifically, the exception states:

Jet Pump Assembly: Inspections for inaccessible welds, beam (UT), and

scheduled inspections of high ranked welds have been deferred, but the

deferrals are technically justified.

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The associated note to this exception states:

Welds at TS-1, TS-3 and TS-4 are inaccessible for inspection. There is no

inspection technique developed to inspect the thermal sleeve welds. However,

the BWRVIP/EPRI NDE Center has new plans to develop an inspection

capability. The BWRVIP is also pursuing analyses which may reduce or alleviate

inspection of the TS-1 through TS-4 welds. Inspection is recommended when

techniques or accessibility becomes available. Also, there are other welds mainly

along the diffuser lower section where coverage is low due to interference from

core shroud gussets, tie rods, and others. The BWRVIP is also pursuing an

analysis to reduce or alleviate inspection of the adapter welds. A technical

justification for inspecting inaccessible jet pump welds, and the deferral of beam

UT inspection has been prepared per BWRVIP-94 guidelines. Finally, several

high priority ranked welds in JP-1,2,3, 4, 19 and 20 previously scheduled for

inspection in R016, were deferred to R017 (one cycle deferral) with technical

justification.

The BWRVIP's augmented inspection and flaw evaluation criteria for BWR jet pump assembly

components are provided in Topical Report BWRVIP-41 and approved by the staff in an SE

dated June 5, 2001. The report recommends either specific visual or volumetric examination

methods for the various jet pump assembly components that are within the scope of

BWRVIP-41. The report also includes the specific details on the inspection frequencies and

sample sizes that are recommended for these examinations.

During the audit and review, the staff asked the applicant to provide its basis for deferring the

augmented examinations for those JAFNPP jet pump assembly components addressed in

Footnote 2 and for concluding that additional augmented inspections of other jet pump

assembly components in BWRVIP-41 will be sufficient to ensure the integrity of the jet pump

assemblies during the period of extended operation.

In its response, the applicant stated that New York Power Authority (the previous owner of

JAFNPP) replaced the jet pump hold down beams in 1992. The applicant clarified that the

decision to defer the baseline examinations of the jet pump assembly from RO16 (Fall 2004) to

R017 (Fall 2006) was based on other higher priorities for inspecting the RPV components. The

applicant clarified that it did perform the augmented examinations of all twenty jet pump

assembly hold-down beams during RO1 7 as recommended in BWRVIP-41 and that the

examinations did not result in any recordable indications in these components. Based on the

replacement of the jet pump hold-down beams in 1992 and lack of indications from the RO1 7

augmented examination results, the staff concludes that it was acceptable to defer the

augmented examinations of the jet pump hold-down beams for a period of one cycle. The staff

concludes that a deferral by one RO for performing the inspections of the jet pump assembly

components is a decision that is limited to the current licensed operating period for JAFNPP

and will not impact the applicant's schedule for inspecting these locations during the period of

extended operation.

The applicant also clarified that it performed augmented examinations of the high-priority jet

pump welds in the jet pump diffuser and adapter and jet pump lower ring assemblies as

recommended in BWRVIP-41. The applicant stated that these examinations resulted in

recordable indications in the DF-2 welds in jet pumps Nos. 1 and 3 and in the AD-3b/DF-3

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welds in jet pumps Nos. 12 and 17. The applicant stated that these indications were determined

to be acceptable for further service in accordance with the staff-approved flaw evaluation

methods in BWRVIP-41. The staff finds this acceptable because the applicant has evaluated

the flaws in accordance with the methods in BWRVIP-41, approved in the staff's SE dated

June 5, 2001. On this basis, this exception is acceptable.

Exception 5. The LRA states an exception to the GALL Report program elements "parameters

monitored/inspected." Specifically, the exception states:

JAFNPP uses ASME Section XI Table IWB-2500-1 from the 1998 edition with

2000 addenda, which is a different code year than that specified in

NUREG-1801.

The applicant's note on this exception provides the following clarifications:

Since ASME Section XI through the 2003 Addenda has been accepted by

reference in 10CFR50.55a(b) (2) without modification or limitation on use of

Table IWB-2500-1 from the 1998 edition with 2000 addenda for BWR

components, use of this version is appropriate to assure that components

crediting this program can perform their intended function consistent with the

current licensing basis during the period of extended operation. The JAF plant

has also submitted a relief request to use BWRVIP inspections, for the most

part, in lieu of ASME XI.

The applicant entered the fourth ten-year ISI interval for JAFNPP in January 2007. The

applicant was required by 10 CFR 50.55a(g)(4)(i) to update the ASME Code Section XI

(Section XI code of record) to the 2001 Edition of Section Xl, inclusive of the 2003 Addenda.

The staff requested clarification from the applicant on whether the Section XI code of record for

the fourth ten-year ISI interval is the 2001 Edition of Section XI, inclusive of the 2003 Addenda.

The applicant clarified in its response that the 2001 Edition of ASME Code Section XI, inclusive

of the 2003 Addenda will be the new Section XI code of record for those JAFNPP AMPs

referencing or crediting ASME Code Section XI requirements. The applicant also stated that

LRA Section A.2.1.18 will be amended to delete the relevant information for the third ten-year

ISI interval and to incorporate the relevant information for the fourth ten-year ISI interval for

JAFNPP, including a statement that the 2001 Edition of ASME Code Section XI, inclusive of the

2003 Addenda is the applicable edition of Section XI for the fourth ten-year ISI interval. The

staff confirmed that the applicant revised the LRA in a letter dated February 1, 2007 (LRA

Amendment No. 5).

The ASME Code Section XI, Examination Category B-N-i, B-N-2 and B-N-3 requirements

provide the 10-Year Interval ISI requirements for inspecting the BWR internals at JAFNPP. The

4'h 10-Year ISI Interval for JAFNPP will be the 10-Year interval in effect, if the LRA for JAFNPP

is approved by the staff. In its exception to the GALL Report, the applicant has appropriately

revised the LRA to refer to the Edition of Section XI that will be in effect upon issuance of

renewed operating license for the facility (pending its approval). This is in compliance with the

requirements of 10 CFR 50.55a and in conformance (i.e., consistent) with the "scope of

program" element in GALL AMP XI.M9, "BWR Vessel Internals," and is acceptable.

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Operating Experience. In LRA Section B.1.7, the applicant provides a summary of the operating

experience that is applicable to reactor vessel (RV) internals at JAFNPP. The applicant stated

that self-assessments of the BWR Vessel Internals Program in 2004 and 2005 reveal no

issues, signs of weakness, or findings with regard to the program's effectiveness.

The applicant indicated that the following age-related operating experience was applicable to

RV internal components at JAFNPP:

Steam Dryer - The applicant stated that multiple steam dryer upper support ring cracks were

detected during refueling outage (RO) 10 (in 1992). The applicant stated that subsequent visual

examination in the same area during R014 (in 2000) revealed no change in the cracks. The

applicant also stated that cracking due to intergranular stress corrosion cracking (IGSCC) was

detected in the steam dryer during R016 (in 2004). The applicant stated that the degraded area

will be visually re-examined in R017.

Topical Report BWRVIP-139 provides the BWRVIP's recommended inspection and flaw

evaluation guidelines for BWR steam dryers. BWRVIP-139 is still pending staff approval.

During the audit and review, the staff asked the applicant to clarify what type of aging

management strategy (i.e., program) was being used to manage cracking in the steam dryer.

The staff also informed the applicant that, if the applicant is crediting BWRVIP-139 for aging

management of the steam dryer, the applicant must place a commitment on the LRA to use the

staff-approved version of BWRVIP-139, once the approved version of the report is issued.

Further, this commitment must be referenced in LRA Section A.2.1.7.

The applicant clarified in its response that Entergy will manage age-related degradation of the

steam dryer in accordance with Topical Report BWRVIP-1 39, as approved by the staff and

accepted by the BWRVIP Executive Committee. The applicant stated that LRA Sections B.1.7,

and A.2.1.7 will be amended to specify that the BWR Internals Program will be enhanced to

state that Topical Report BWRVIP-139 will be used as the basis for managing the aging effects

applicable to the steam dryer at JAFNPP. The applicant stated that the enhancement will be

incorporated into a commitment on the LRA and will require a license amendment.

In its letters dated December 6, 2006, the applicant amended LRA Section B.1.7 and A.2.1.7 to

specify that the BWR Internals Program is enhanced to the staff-approved version of

BWRVIP-1 39 for aging management of the steam dryer and that this enhancement is provided

in LRA Commitment No. 22 (JAFP-06-0167, dated December 6, 2006). This commitment

specifically states that the applicant will enhance the BWRVIP to ensure that the effects of

aging of the steam dryer are managed in accordance with the guidelines of BWRVIP-139, as

approved by the staff and acceptable by the BWRVIP Executive Committee. Commitment

No. 22 must be implemented prior to entering the period of extended operation. Staff finds this

is acceptable because the applicant will use the staff-approved version of BWRVIP-139 for

aging management of the steam dryer at JAFNPP.

Core Shroud - The applicant stated that during R014 (in 2000), crack-like indications were

detected in four of the vertical seam welds in the core shroud. The applicant reported that the

most limiting core shroud weld, Weld No. SV5B, was re-examined in RO1 5 (in 2002) with no

discernible changes in the indications; however, the applicant reported that an additional

indication has been detected. The applicant stated that several of the core shroud vertical welds

are scheduled for ultrasonic examination in R017.

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During the audit and review, the staff asked the applicant to clarify whether or not the JAFNPP

core shroud had been repaired with mechanical repair assemblies (i.e., either tie rod or

mechanical clamp assemblies) and if so, to identify which core shroud welds the repair

assemblies were assuming the loading conditions for and which welds were not covered by the

repair assemblies. The staff also asked the applicant, during the audit and review, to discuss

what type of examination methods, frequencies and sample sizes were being credited for aging

management of the JAFNPP core shroud and its repair assemblies.

The staff also noted that the applicant had reported the occurrence of flaw indications in core

shroud vertical welds SV5A and SV5B. Core shroud repair hardware assembly designs assume

the tensile loading conditions in core shrouds but do not assume the circumferential loading

conditions (hoop stress conditions) for the shrouds. Flaw growth of cracking in vertical core

shroud seam welds is predominantly.driven by hoop stresses.

During the audit and review, the staff asked the applicant to resolve the following technical

questions relative to the cracking that was detected in the shroud vertical welds:

Identify what type of cracking mechanism was determined to be the root cause of the

cracking in the vertical welds;

" Identify what type of inspection methods were used to re-examine the impacted welds

for signs of flaw growth, as visual examinations are not valid methods to verify whether

flaw growth is occurring;

" Clarify, with a supporting technical justification, why Entergy considers the relevant flaw

indications to be acceptable for further service without mandating proper repair of the

indications.

" Clarify and discuss what type of non-destructive examination method Entergy will be

implementing to reexamine the vertical welds in the core shroud if the indications in the

vertical welds have been determined to be acceptable for further service, or clarify what

type of repair contingencies Entergy will implement if the indications in the shroud

vertical welds are determined to be unacceptable for further service.

The applicant stated in its response that ten (10) core shroud tie rod assemblies were installed

on the outside of core shroud in 1994. The applicant clarified that the tie rod assemblies were

installed to assume the loading conditions in the core shroud during normal operations

(including heatups and cooldowns of the reactor and anticipated operational transients),

pressure test conditions, and postulated design basis events. The applicant clarified that the tie

rod assemblies include associated radial seismic restraints that are designed to limit lateral

movement of the shroud during these type of conditions. The applicant also stated that it

manages the aging effects associated with the core shroud and the core shroud tie rod

assemblies in accordance with the inspection and flaw evaluation criteria provided in Topical

Report BWRVIP-76.

The applicant also clarified that the flaw indications of core shroud vertical welds SV5A and

SV5B were attributed to intergranular stress corrosion cracking and that the crack indications

were detected and sized using UT examination techniques. The applicant clarified that these

flaw indications were evaluated in accordance with the augmented flaw evaluation acceptance

criteria in BWRVIP-76 and flaw indications were determined to be acceptable for further service

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until refueling outage (RO) 18. The applicant stated that it will perform a calculation in

accordance with the BWRVIP-76 flaw evaluation criteria that will be used to establish the

inspection frequency and sample size for the re-inspections of the core shroud vertical welds.

Topical Report BWRVIP-76 provides the BWRVIP's recommended inspection and flaw

evaluation guidelines for BWR core shrouds. The staff approved BWRVIP-76 for

implementation and the augmented inspection basis for BWR core shrouds and core shroud

repair assemblies in staff SEs dated July 27, 2006 (Proprietary SE) and July 28, 2006

(Non-Proprietary SE). As stated earlier in this evaluation, the staff has confirmed that the

applicant is both implementing the BWRVIP implementation guidelines of BWRVIP-94 and the

staff-approved inspection and flaw evaluation criteria of BWRVIP-76 for the inspection of the

JAFNPP core shroud (including the shroud vertical welds) and the core shroud tie rod repair

assemblies. Based on the applicant's response to the staff's question, the staff concludes that it

is acceptable to use BWRVIP-76 as the basis for managing cracking in the JAFNPP core

shroud and core shroud tie rod assemblies. The staff questions on aging management of the

core shroud and core shroud tie rod repair assemblies are resolved.

Core Spray Piping Cracking - The applicant stated that it had detected a core spray piping

indication reported in R014 (2000) and was re-examined (after brushing) in R015 (2002).

Re-examination revealed no change in the length of the indication and the applicant concluded

that the indication is a scratch rather than a crack.

The staff also reviewed operating experience reports and confirmed that the plant-specific

operating experience did not include any aging effects for systems and components within the

scope of this program that are not bounded by industry operating experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.7, the applicant provided the UFSAR supplement for

the BWR Vessel Internals Program. The staff reviewed this section and determined that

UFSAR Supplement Section A.2.1.7 provided a sufficient technical description of the BWRVIP

but did not reflect the need for an additional commitment on the LRA to use the staff-approved

version of BWRVIP-139 for the aging management of the JAFNPP steam dryer. The staff

determined that LRA Section A.2.1.7 should be amended to reflect this commitment.

In letters dated December 6, 2006, the applicant amended the LRA Section B.1.7 and A.2.1.7

to specify that the BWR Internals Program is enhanced to use the staff-approved version of

BWRVIP-1 39 for aging management of the steam dryer and that this enhancement is provided

in LRA Commitment No. 22.

In its response dated February 1, 2007, the applicant stated that LRA Section B.1.7 and A.2.1.7

" in addition to the scope described in GALL Report, JAFNPP Scope also includes the steam

dryer: BWRVIP-139 and GE SIL 644, Rev. 1, provide guidelines for inspection and evaluation.

JAFNPP follows BWRVIP-139 and GE SIL 644, Rev. 1 guidelines."

Based on the LRA amendment, the staff concludes the information in the UFSAR

Section A.2.1.7 provides an adequate summary description of the program, as required by

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10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BWR Vessel Internals

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and the

associated-justifications, and determined that the AMP is adequate to manage the aging effects

for which it is credited. The staff concludes that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

.3.0.3.2.8 Diesel Fuel Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.9 describes the existing

Diesel Fuel Monitoring Program as consistent, with exception and enhancements, with GALL

AMP XI.M30, "Fuel Oil Chemistry."

The program entails sampling to maintain adequate diesel fuel quality to prevent corrosion of

fuel systems. Exposure to fuel oil contaminants like water and microbiological organisms is

minimized by periodic sampling and analysis, draining and cleaning of tanks, and verifying the

quality of new oil before its introduction into the storage tanks.

The enhancements to this program will be implemented prior to the period of extended

operation. This is Commitment No. 3 (JAFP-06-0109, dated July 31, 2006) in the applicant's

letter dated December 6, 2006.

Staff Evaluation. During its audit and review, the staff reviewed the exception and

enhancements to determine whether the AMP, with the exception and enhancements, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical staff and reviewed the Diesel Fuel Monitoring

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine their consistency with GALL AMP XI.M30.

In addition, to assess the applicant's compliance with the ASTM standards, the staff reviewed

the following:

" D 4057, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products,"

dated 1995

" D 975, "Standard Specification for Fuel Oils," dated 2006

0 D1 796, "Standard Test method for Water and Sediment in Fuel Oils by the Centrifuge

Method," dated 2004

0 D 2276, "Standard Test method for Particulate Contaminant in Aviation Fuel by Line

Sampling," dated 2000

D 6217, "Standard Test Method for Particulate Contamination in Middle Distillate Fuels

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by Laboratory Filtration," dated 2003

The staff verified that the applicant's Diesel Fuel Monitoring Program includes sampling and

analysis activities on diesel fuel that are in accordance with ASTM standard D 4057 for

sampling, D 975 for analysis, D 1796 for water and sediment monitoring, and D 6217 for

particulates monitoring. The applicant also measures flashpoint for the diesel fuel. These

activities are consistent with the recommendations in GALL Report.

During the audit and review, the staff asked the applicant to provide the sampling frequency for

the diesel fuel storage tanks. In its response, the applicant stated that the EDG fuel oil storage

tanks are sampled every 31 days, and the diesel fire pump fuel oil tanks are sampled every 92

days. The staff reviewed plant procedure SP-01.07, "Diesel Fuel Oil Sampling and Analysis,"

Revision 7, and confirmed the sampling frequencies. The staff also verified that the sampling

frequencies are in accordance with the plant's Technical Specifications. The staff determined

that the sampling frequencies are consistent with current industry standards, and are consistent

with the plant technical specifications. The sampling frequencies will provide for timely detection

of fuel oil contamination, and will allow corrective actions to be taken, as needed, prior to the

loss of intended function. On this basis, the staff finds these sampling frequencies acceptable.

The staff finds the applicant's Diesel Fuel Monitoring Program acceptable because it is

consistent with the recommended GALL AMP XI.M30, "Fuel Oil Chemistry," with the exception

and enhancements as described:

Exception. The LRA states an exception to the GALL Report program elements "scope of

program," "parameters monitored or inspected," and "acceptance criteria." Specifically, the

exception states:

The guidelines of ASTM Standard D 2276 are not used for determination of

particulates.

The staff noted that the discussion of this exception of the LRA includes a footnote, which

states the following:

JAFNPP technical specifications specify use of ASTM D 6217, which is a test

specifically for diesel fuel, rather than ASTM D 2276, which is for aviation fuel.

Therefore, the guidelines of D 6217 are appropriate for determination of

particulates.

The staff noted that GALL AMP XI.M30 recommends ASTM D 2276 or D 6217 for the

measurement of particulates in diesel fuel. The staff reviewed both standards and determined

that ASTM standard D 2276 is applicable for aviation fuels, while D 6217 is applicable for

middle distillate fuels, such as that used at JAFNPP. The staff verified that the use of ASTM

standard D 6217 is consistent with the requirements in the plant technical specifications.

Therefore, the staff concludes that this exception is acceptable.

Enhancement 1. The LRA states an enhancement to the GALL Report program elements

"preventive actions" and "detection of aging effects." Specifically, the enhancement states:

The diesel fuel monitoring program will be enhanced to include periodic draining,

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cleaning, visual inspections, and ultrasonic measurement of the bottom surfaces

of the fire pump diesel fuel oil tanks, EDG day tanks, and EDG fuel oil storage

tanks to ensure that significant degradation is not occurring.

During the audit and review, the staff asked the applicant for additional details on the frequency

for draining, cleaning, and inspecting the diesel fuel storage tanks. In its response, the applicant

stated that the emergency diesel underground fuel oil storage tanks are cleaned and inspected

on an eight-year frequency and were UIT inspected in 1988. These inspections have not

revealed any degradation in the surface of the tank. Inspections are performed on the tank

,bottoms since this is where water and sediment accumulate, making the bottoms the most

susceptible area for corrosion. The applicant proposed to continue to inspect these tanks on

this eight-year frequency. based on past inspection results.. If any significant corrosion is

detected, inspections on adjacent areas of the tank bottom will be performed using the

appropriate grid size based on the size of the tank.

The applicant also stated that the fire pump diesel fuel oil tanks and the EDG day tanks will be

inspected on an eight-year frequency similar to the EDG underground storage tanks. This

frequency is based on past inspection results of the EDG underground fuel oil storage tanks,

which have not documented significant degradation and are exposed to the same internal fuel

oil environment. If initial inspections find unexpected conditions, the frequency will be adjusted

via the corrective action process.

The staff determined that the applicant's enhancement will add routine draining, cleaning, visual

inspections, and ultrasonic measurement of the bottom surfaces of the diesel fuel tanks, which

are consistent with the recommendations in the GALL Report. The frequency for draining,

cleaning and inspecting the tanks will be based on past experience, which has been

demonstrated to provide acceptable performance for the diesel fuel storage tanks. Ultrasonic

measurement of the tank bottoms will provide objective evidence that degradation of the tanks

is not occurring. The staff finds that the selection of the tank bottoms for ultrasonic inspection is

appropriate since any moisture in the oil will tend to settle to the bottom of the tanks, making

this the most susceptible location for degradation. The staff finds the enhancement acceptable

because with the enhancement, the Diesel Fuel Monitoring Program will be consistent with

GALL AMP XI.M30 and will add assurance of adequate management of aging effects

(Commitment No. 3).

Enhancement 2. The LRA states an enhancement to meet the GALL Report program element

"Acceptance Criteria." Specifically, the enhancement states:

The diesel fuel monitoring program will be enhanced to specify acceptance

criterion for UIT measurements of diesel generator fuel storage tanks within the

scope of this program.

The staff determined that the applicant's enhancement will specify acceptance criteria for UT

measurements of diesel generator fuel storage tanks within the scope of this program, which is

consistent with the recommendations in the GALL Report. The acceptance criteria will provide a

measure to determine whether corrective actions are required based upon inspection results.

The staff finds the enhancement acceptable because with the enhancement, the Diesel Fuel

Monitoring Program will be consistent with GALL AMP XI.M30 and will add assurance of

adequate management of aging effects (Commitment No. 3).

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Operating Experience. LRA Section B.1.9 states that in 2000 sample results for EDG fuel oil

storage tanks (93TK-6B and D) exceeded the industry acceptable limit for particulate

contamination. Resample results of TK-6B were acceptable. Storage tank TK-6D was drained

and refilled with fresh fuel oil. In May 2000 approximately 20 gallons of fuel oil were added to

fire pump diesel fuel oil tank 76TK-10 from a fuel oil tank that had not been sampled to ensure

that it met fuel oil quality requirements. In 2002, trending of bottom sample results for EDG fuel

oil storage tank 93TK-6C showed a particulate contamination increase from 3 mg/liter to 6-8

mg/liter. Two thousand gallons of fuel oil were removed from the bottom of the tank and the

tank was refilled with fresh fuel oil. In 2004, the testing frequency for new fuel oil was not per

requirements. Technical specifications require that within 31 days following addition of the new

fuel oil to storage tanks properties of the new fuel oil be verified as within the limits for the

American Society for Testing and Materials 2D fuel oil. Results from samples of new fuel oil

sent to offsite testing facilities were not received within the 31-day time frame. Procedures were

revised and new testing vendors were employed to prevent recurrences of such events. Other

than these instances, fuel oil sampling results from 2000 through 2004 revealed that fuel oil

quality has been maintained in compliance with acceptance criteria. Visual inspections of EDG

fuel oil tank internals in 1995 (93TK-6B), 2001 (93TK-6A and D), and 2004 (93TK-6C) revealed

no degradation. Ultrasonic inspections of the EDG fuel oil tanks in 1988 also revealed no

degradation. Continuous confirmation of diesel fuel quality, timely corrective actions, and

absence of degradation in the fuel oil storage tanks prove that the program is effective in

managing loss of material of fuel system components.

The staff reviewed the Diesel Fuel Monitoring Program operating experience in the LRA and

determined that it has detected increases in the contamination level of the diesel fuel in a timely

manner such that corrective actions could be taken prior to the loss of intended function of the

components. In cases where contaminant levels were exceeded, corrective actions included

resampling or replacement of the fuel. Resampling is appropriate to verify that the initial results

were not anomalies caused by inappropriate sampling procedures. After results are confirmed,

replacement of the contaminated fuel is an appropriate corrective action to remove

contaminants from the fuel stream. Instances in which the fuel sampling frequency was not met

were also identified. In these instances, the applicant revised the plant procedures and used

different vendors to provide more timely analysis of the fuel. These corrective actions are

appropriate to ensure future sampling frequencies are met.

The staff also reviewed the operating experience reports and confirmed that the plant-specific

operating experience did not include any aging effects for systems and components within the

scope of this program that are not bounded by industry operating experience. The staff noted

that none of the condition reports identified as aging-related involved components exposed to

diesel fuel oil. The staff finds that this an acceptable indication that components in the diesel

fuel systems at JAFNPP are not experiencing any aging effects that are not bounded by

industry operating experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.9, the applicant provided the UFSAR supplement for

the Diesel Fuel Monitoring Program. The staff reviewed the applicant's license renewal

commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and

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confirmed that enhancements to this program is identified as Commitment No. 3, to be

implemented before the period of extended operation. The staff determines that the information

in the UFSAR supplement is an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Diesel Fuel Monitoring

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and the

associated justifications, and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. Also, the staff reviewed the enhancements

and confirmed that the implementation of the enhancements prior to the period of extended

operation would result in the existing AMP being consistent with the GALL AMP to which it was

compared. The staff concludes that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.9 External Surfaces Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.11 describes the existing

External Surfaces Monitoring Program as consistent, with enhancement, with GALL

AMP XI.M36, "External Surfaces Monitoring."

This program entails inspections of external surfaces of components subject to an AMR. The

program is also credited with managing loss of material from internal surfaces where internal

and external material and environment combinations are the same and the external surface

condition represents the internal.

Staff Evaluation. During its audit and review, the staff reviewed the enhancement to determine

whether the AMP, with the enhancement, remains adequate to manage the aging effects for

which it is credited.

The staff interviewed the applicant's technical staff and reviewed the External Surfaces

Monitoring Program bases documents. Specifically, the staff reviewed the program elements

and associated bases documents to determine consistency with GALL AMP XI.M36.

The staff determined that this program uses visual inspection methods to manage loss of

material for external surfaces of components. The program also manages loss of material from

internal surfaces and for situations in which internal and external material and environment

combinations are the same (e.g., external surface condition is representative of internal surface

condition). Surfaces that are inaccessible during plant operations are inspected during refueling

outages. Surfaces are inspected at regular frequencies to provide assurance that the effect of

aging will be managed such that applicable components will perform their intended function

during the period of extended operation.

The staff finds the applicant's External Surfaces Monitoring Program acceptable because it is

consistent with the recommended GALL AMP XI.M36, "External Surfaces Monitoring," with an

enhancement as described:

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Enhancement. The LRA Section B. 1.11 states an enhancement to the GALL Report program

element "scope of program." Specifically, the enhancement states:

External surfaces monitoring program guidance documents will be enhanced to

clarify license renewal commitment. The commitment for license renewal is for

periodic inspections of systems in scope and subject to aging management

review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3).

Inspections shall include areas surrounding the subject systems to identify

hazards to those systems. Inspections of nearby systems that could impact the

subject systems will include SSCs that are in scope and subject to aging

management review for license renewal in accordance with 10 CFR 54.4(a)(2).

The staff determined that the applicant currently performs inspections of the systems within the

scope of this program; however, the guidance documents used to perform these inspections

may not include a requirement to inspect surrounding areas, which is required for license

renewal. This enhancement will add a requirement to the existing plant guidance documents to

include areas surrounding the subject systems to identify hazards to those systems. The staff

determined that inspection of surrounding areas to identify potential hazards that could damage

the system components is appropriate, since these hazards could result in a loss of system

function. Adding a requirement to inspect surrounding areas will provide assurance that no

hazards exist and will make the AMP consistent with the recommendations in the GALL Report.

On this basis, the staff finds this enhancement acceptable (Commitment No. 4 (JAFP-06-0109,

dated July 31, 2006)).

Operatinq Experience. LRA Section B. 1.11 states that external Surface Monitoring walkdowns

between 2000 and 2004 detected evidence of aging effects, including corrosion and leakage.

Corrective actions were implemented in accordance with the site corrective action program.

Detection of degradation and corrective action prior to loss of intended function prove that the

program is effective for managing aging effects for passive components.

The staff interviewed the applicant's staff and also reviewed operating experience reports and

confirmed that the plant-specific operating experience did not include any aging effects for

systems and components within the scope of this program that are not bounded by industry

operating experience. The JAFNPP operating experience included detection of corrosion on

component external surfaces, as well as external leakage from valves. These aging effects are

consistent with industry operating experience, and this AMP includes aging management

activities, such as visual inspections, that are appropriate to detect these aging effects.

Corrective actions were taken in accordance with the plant corrective action program prior to a

loss of intended function of the component.

To confirm the effectiveness of this program, the staff reviewed two plant condition reports

(CRs). In one CR, the applicant documents the discovery of a small packing leak in the HPCI

steam supply isolation valve during a system walkdown inspection. The valve leakage condition

was documented, a work order was performed to adjust the packing, and the leak was repaired.

In the second CR, the applicant documents the detection of corrosion under the metal roof

decking of the auxiliary boiler building during a structural monitoring walkdown. The condition of

the roof was documented and evaluated. The applicant determined that there were no structural

concerns associated with the condition at that time and the monitoring frequency was increased

to a 2-year cycle (from 5 years). These examples are verification that system problems are

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being detected by the program and corrective actions are being implemented.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.11, theapplicant provided the UFSAR supplement

for the External Surfaces Monitoring Program. The staff reviewed the applicant's license

renewal commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1,

2007 and confirmed that the program enhancement is identified as Commitment No. 4, to be

implemented before the period of extended operation.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's External Surfaces Monitoring

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report, are consistent. Also, the staff reviewed the enhancement and confirmed

that the implementation of the enhancement prior to the period of extended operation would

result in the existing AMP being consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.10 Fatigue Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.12 describes the existing

Fatigue Monitoring Program (FMP). The applicant identified this program as an existing AMP

that is consistent with program attributes in GALL AMP X.M1, "Metal Fatigue of Reactor

Coolant Pressure Boundary," with exceptions.

That applicant stated that in order not to exceed usage design limits on fatigue, the FMP tracks

the number of critical thermal and pressure transients for selected reactor coolant system

components. The program validates analyses that explicitly assume a specified number of

fatigue transients by assuring that the actual effective number of transients is not exceeded.

In a letter dated November 7, 2007 (LRA Amendment No. 14), the applicant amended the LRA

to state that the Fatigue Monitoring Program is consistent with GALL AMP X.M1, "Metal Fatigue

of the Reactor Coolant Pressure Boundary," without exception.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report.

The staff interviewed the applicant's technical staff and reviewed the Fatigue Monitoring

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP X.M1.

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The staff reviewed those portions of the Fatigue Monitoring Program for which the applicant

claimed consistency with GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure

Boundary," and found them consistent.

In letters dated August 14, 2007 and November 5, 2007, the applicant amended the LRA and

supplemented Commitment No. 20 with respect to its basis for its environmentally-assisted

fatigue analysis. In its letter dated November 5, 2007, the applicant clarified that Option 1 of

Commitment No. 20 for refined CUF calculations is consistent with the NRC's recommendations

for the periodic CUF updates in the "monitoring and trending" (i.e., program element 4) and for "corrective actions" in GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure

Boundary." The applicant also clarified that Options 2 and 3 of Commitment No. 20 are

considered to be corrective actions that are consistent with the corrective actions recommended

in the "corrective action" (i.e., program element 7) of the same GALL AMP.

Based on these clarifications, the applicant amended the LRA to bring Commitment No. 20

within the scope of the applicant's Fatigue Monitoring Program and to credit this AMP as the

basis for accepting this TLAA in accordance with 10 CFR 54.21(c)(1)(iii). In the LRA

amendment, the applicant also stated that the Fatigue Monitoring Program is consistent with

GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure Boundary," without

exception. The staff determined that the changes proposed by the applicant are consistent with

the NRC's recommendations in GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant

Pressure Boundary." Based on this assessment, the staff concludes that the Fatigue Monitoring

Program is consistent with GALL AMP X.M1 without exception and is acceptable.

Operating Experience. LRA Section B.1.12 states that for recent reactor shutdowns and

startups cycle limitations did not trend toward exceeding the allowable number of cycles but

demonstrated that the program continues to monitor plant transients and track their

accumulation.

The staff interviewed the applicant's technical staff and also reviewed the operating experience

reports and confirmed that the plant-specific operating experience did not include any aging

effects for systems and components within the scope of this program that are not bounded by

industry operating experience.

A review of sample condition reports indicated that potential nonconforming conditions are

identified, evaluated and resolved. The staff found that the corrective action program, which

captures internal and external plant operating experience issues, will ensure that operating

experience is reviewed and incorporated in the future to provide objective evidence to support

the conclusion that the effects of aging are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.12, the applicant provided the UFSAR supplement

for the Fatigue Monitoring Program. The staff determines that the information in the UFSAR

supplement provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

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Conclusion. On the basis of its audit and review of the applicant's Fatigue Monitoring Program,

the staff determines 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).

3.0.3.2.11 Fire Protection Program

Summary of Technical Information in the Application. LRA Section B. 1.13.1 describes the

existing Fire Protection Program as consistent, with enhancements, With GALL AMP XI.M26,

"Fire Protection."

The Fire Protection Program includes a fire barrier inspection and a diesel-driven fire pump

inspection. The fire barrier inspection requires periodic visual inspection of fire barrier

penetration seals, fire dampers and frames, fire barrier walls, ceilings, and floors, and periodic

visual inspection and functional tests of fire-rated doors to maintain their operability. The

diesel-driven fire pump and its driver are tested periodically to ensure that diesel engine

subsystems, including the fuel supply line, can perform their intended functions.

Staff Evaluation. During its audit and review, the staff reviewed the enhancements to determine

whether the AMP, with the enhancements, remains adequate to manage the aging effects for

which it is credited.

The staff interviewed the applicant's technical staff and reviewed the Fire Protection Program

bases documents including the Technical Requirement Manual (TRM). Specifically, the staff

reviewed the program elements and associated bases documents to determine consistency

with GALL AMP XI.M26.

The staff identified during its review that the applicant did not include the Halon/C0 2 fire

suppression system within the scope of the Fire Protection Program as recommended by GALL

Report XI M26. The GALL Report recommends that an AMP be established to evaluate the

periodic visual inspection and functional testing at least once every six months to examine the

signs of degradation of the Halon/CO2 fire suppression system. Material conditions that may

affect the performance of the system, such as corrosion, mechanical damage, or damage to

dampers, are observed during these tests.

During the audit and review, the staff asked the applicant why the CO 2 system is not included in

the Program Description of the AMP.

In its response, the applicant stated that it will include CO 2 within the scope of the program. In

its response dated February 1, 2007, the applicant amended the LRA (Amendment No. 5) "program description" Section B.1.13.1 to state "The program also includes Plant CO2 fire

suppression system valve position checks and operational tests, CO 2 storage tank level and

pressure checks, system functional checks, and external surface inspections," and added an

exception to the GALL element "detection of aging effects."

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As noted in LRA Table 3.3.2-6, the aging effects of the fire protection-CO 2 fire suppression

system are managed by the Bolting Integrity Program (Section B.1.30) and by the Fire

Protection Program (B.i.13.1). However, no mention of the Halon fire suppression system was

mentioned in LRA Section B.1.13.1. A review of UFSAR 9.8.3.11 indicated that the halon fuel

suppression system is used for fire protection in the Emergency and Plant Information

Computer (EPIC) Room, where it is not desirable to use a water spray or a sprinkler system.

The staff asked the applicant, during the audit and review, if the system is credited for a safe

shutdown in any fire scenarios pursuant to1O CFR 50.48 and if so, provide justification of why

an AMP is not required or provide an AMP that contains the required ten elements. In its

response, the applicant stated that the EPIC system is not credited for a safe shutdown in any

fire scenarios to demonstrate compliance with 10 CFR 50.48. The halon fire suppression

system is required for insurance purposes but is not required to protect safety-related systems.

Therefore, the system has no intended functions pursuant to 10 CFR 54.4(a)(1) or (a)(3). Also,

since the system does not contain liquids that could leak and cause physical interaction with

safety-related components, it does not have any intended functions pursuant to

10 CFR 54.4(a)(2). Based on the above and since the system does not have any

license-renewal-related intended functions, the staff determined that the applicant's response is

acceptable.

The staff reviewed those portions of the Fire Protection Program for which the applicant claims

consistency with GALL AMP XI.M26 and found that they are consistent with the GALL AMP.

Furthermore, the staff concludes that the applicant's Fire Protection Program reasonably

assures management of aging effects so components crediting this program can perform

intended functions consistent with the CLB during the period of extended operation. The staff

finds the applicant's Fire Protection Program acceptable because it conforms to the

recommended GALL AMP XI.M26, "Fire Protection," with an exception and enhancements as

described below

Exception. The LRA states the following exception to the GALL Report program element:

Element: 4: detection of aging effects

Exception: The six-month periodicity listed in NUREG-1801 for the full CO 2

system functional test will be performed on a 24-month basis in

accordance with the plant's current licensing basis.

The staff noted that the GALL Report recommends a six-month periodicity for the full CO2

system functional test. The CLB for JAFNPP is to perform the full CO 2 system functional test on

a 24-month basis in accordance with JAFNPP TRM Section 3.7.J. The 24-month CO2 system

functional test frequency is specified in the JAFNPP Fire Protection Program and was part of

the original licensing basis until the fire protection limiting conditions for operation and

surveillance requirements was removed from the technical specifications based on the

GL 88-12, "Removal of Fire Protection Requirements from Technical Specifications," dated

August 1988, and placed in the plant TRM.

The CO2 fire suppression installed at the JAFNPP is based on the National Fire Protection

Association (NFPA) 12, "Standard on Carbon Dioxide Extinguishing Systems," 1968 Edition

(Code of Record). The NFPA 12, 1968 Edition did not specify any frequency for the CO 2 fire

suppression system functional test. The surveillance frequency for the CO 2 fire suppression

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system to perform functional test provided in the GALL Report is based on the current

NFPA 12.

In addition, the staff noted that the applicant currently performs quarterly (92 days) CO 2 fire

suppression system valve position check and operational tests and monthly CO 2 fire

suppression system storage tank level'and pressure checks. JAFNPP maintenance procedures

also include visual inspections of component external surfaces for signs of corrosion and

mechanical damage. The applicant's review of station operating experience identified no

aging-related degradation adversely affecting the operation of the CO 2 fire suppression system.

The 24-month C02 fire suppression functional test frequency is part of the CLB and the review

of JAFNPP operating experience indicated that this frequency is reasonable to manage the

aging effects. The 24-month frequency is considered sufficient to ensure system availability and

operability based on the plant operating history, and that there has been no aging-related event

that has adversely affected system operation. Because these aging effects occur over a

considerable period of time, the staff concluded that the 24-month inspection interval will be

sufficient to detect aging of C02 fire suppression system. The C02 fire suppression systems

and components are in an inside air (external) environment, bolting, coil nozzles, piping and

supports, tubing, fittings, valves, and tanks in an inside air (external) environment. The staff

found that the applicant had demonstrated that the effects of aging C02 fire suppression

system 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). On these

bases, the staff finds this exception acceptable.

Enhancements. The LRA states that the following enhancements to the GALL Report program

elements prior to the period of extended operation:

Enhancement 1

Elements: 1: scope of program

3: parameters monitored/inspected

4: detection of aging effects

5: monitoring and trending

6: acceptance criteria

Enhancement: The Fire Protection Program will be enhanced to inspect

fire barrier walls, ceilings, and floors at least once every

refueling outage. Inspection results will be acceptable if

there are no visual indications of degradation such as

cracks, holes, spalling, or gouges.

The staff determined that this enhancement is acceptable because when the enhancement is

implemented, Fire Protection Program elements "scope of program," "parameters

monitored/inspected," " monitoring and trending," and "acceptance criteria," will be consistent

with GALL AMP XI.M26 elements "scope of program," "parameters monitored/inspected,""

monitoring and trending," and "acceptance criteria," which state that the inspection of fire

barrier walls, ceilings, and floors at least once every refueling outage and the inspection results

will be acceptable if there are no visual indications of degradation such as cracks, holes,

spalling, or gouges. The applicant identified this enhancement as Commitment No. 5

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(JAFP-06-0109, dated July 31, 2006).

Enhancement 2

Element: 4: detection of aging effects

Enhancement: The Fire Protection Program will be enhanced to inspect at

least one seal of each type every 24 months.

The staff noted that this enhancement did not meet the GALL guidance. Specifically, GALL

AMP XI.M26, "detection of aging effects" element states that approximately 10 percent of each

type of seal should be visually inspected at least once every refueling outage.

During the audit and review, the staff asked the applicant whether the seal inspection covers 10

percent of each type of seal in accordance with AMP XI.M26, "Detection of Aging Effects"

element. In its response dated April 6, 2007, the applicant revised the above enhancement to

state that the fire protection program will be enhanced to verify that each seal type is included in

the 10 percent sample inspected every 24 months.

The staff determined that thisenhancement is acceptable because when the enhancement is

implemented, Fire Protection Program element "detection of aging effects" will be consistent

with GALL AMP XI.M26 "detection of aging effects" element which states that approximately 10

percent of each type of seal should be visually inspected at least once every refueling outage

(2 years).

The applicant identified this enhancement as Commitment No. 5. The staff is adequately

assured that the AMP for penetration seals used for fire barriers will be considered

appropriately during plant aging management activities.

Enhancement 3

Element: 4. detection of aging effects

Enhancement: The Fire Protection Program will be enhanced to include

periodic inspection of diesel-driven fire pump exhaust

system components. These inspections will identify

cracking through the use of visual or other NDE

techniques.

The staff determined that this enhancement is acceptable because when the enhancement is

implemented, Fire Protection Program element "detection of aging effects," will be consistent

with GALL AMP XI.M26.

On this basis, the staff found this enhancement acceptable since when the enhancement is

implemented, the Fire Protection Program will be consistent with GALL AMP XI.M26 and will

provide additional assurance that the effects of aging will be adequately managed. The

applicant identified this enhancement as Commitment No. 5.

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Operating Experience. LRA Section B.1.13.1 states that inspections of fire stops, fire barrier

penetration seals, fire barrier walls, ceilings, and floors from 2000 through 2004 detected such

signs of degradation as cracks, gaps, voids, holes, or missing material. Visual inspections and

functional tests of fire doors from 2000 through 2004 detected degradation of fire doors such as

corrosion, wear, and missing parts. Detection of degradation and corrective action prior to loss

of intended function prove that the program is effective for managing loss of material for fire

barrier components and doors. The diesel-driven fire pump was observed while running in

June 2005. No leaks or degradation of diesel engine subsystems, including the fuel supply line,

were noted. Continual monitoring makes the program effective for managing aging of

diesel-driven fire pump subsystem components.

The applicant also stated in the LRA that QA audits and surveillances in 2002 and 2003

revealed that the material condition of system equipment was good and met licensing

requirements. The audits and surveillances revealed no issues or findings with impact on

program effectiveness to manage aging effects for fire protection components. In March 2005

the NRC completed a triennial fire protection team inspection to assess whether the plant had

implemented an adequate Fire Protection Program and whether post-fire safe shutdown

capabilities have been established and properly maintained. Results confirmed that plant

personnel had maintained the fire protection systems in accordance with their Fire Protection

Program, identified program deficiencies, and implemented appropriate corrective actions. The

team also evaluated the material condition of fire area boundaries, fire doors, and fire dampers

and concluded that plant personnel had maintained passive features in a state of readiness.

The staff reviewed the above operating experience and also operating experience reports and

interviewed the applicant's technical staff and confirmed that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience. The staff also

reviewed the JAFNPP condition reports associated with the corrective actions taken for the

identification of signs of degradation of fire protection components. The staff confirmed that the

CRs were closed out by repairs to the degraded fire barriers or performed adequate

engineering evaluations for their acceptability. The staff noted that the applicant performs

periodic inspections and placed identified deficiencies into their corrective action program to

ensure appropriate corrective actions are performed in a timely manner.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.13, the applicant provided the UFSAR supplement

for the Fire Protection Program. The: staff reviewed the applicant's license renewal commitment

list in LRA Amendment 5, Attachment 1, Revision 1, February 1, 2007, and confirmed that the

program enhancements are identified as Commitment No. 5, to be implemented before the

period of extended operation.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, the

staff finds those program elements, for which the applicant claimed consistency with the GALL

Report, are consistent. In addition, the staff reviewed the exception and the associated

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justification, and determined that the AMP, with the exception, is adequate to manage the aging

effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that

the implementation of the enhancements prior to the period of extended operation would result

in the existing AMP being consistent with the GALL AMP to which it was compared. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.12 Fire Water System Program

Summary of Technical Information in the Application. LRA Section B.1.13.2 describes the

existing Fire Water System Program as consistent, with exceptions and enhancements, with

GALL AMP XI.M27, "Fire Water System."

The applicant states that the program applies to water-based fire protection systems that

consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes,

above-ground and underground piping, and components tested in accordance with applicable

NFPA codes and standards. Such testing assures functionality of systems. Many of these

systems are normally maintained at required operating pressure and monitored to detect

leakage causing loss of system pressure immediately and to initiate corrective actions. In

addition, periodic wall thickness evaluations of fire protection piping on system components use

non-intrusive techniques (e.g., volumetric testing) to find evidence of loss of material due to

corrosion. A sample of sprinkler heads will be inspected in accordance with the guidance of

NFPA 25 (2002 edition) Section 5.3.1.1.1, which states that "where sprinklers have been in

place for 50 years, they shall be replaced or representative samples from one or more sample

areas shall be submitted to a recognized testing laboratory for field service testing." NFPA 25

also has guidance for sampling every 10 years after initial field service testing.

Staff Evaluation. During its audit and review, the staff reviewed the exceptions and

enhancements to determine whether the AMP, with the exceptions and enhancements, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical staff and reviewed the Fire Water System

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M27.

During the audit and review, the staff noted from the LRA's review that there was no aging

management program for water storage tanks as described in the Program Description of

GALL AMP XI.M27. The staff interviewed the JAFNPP technical staff, reviewed piping and

instrumentation diagram and the JAFNPP License Renewal Project Aging Management

Program Evaluation Report. The staff confirmed from the interviews and documentation reviews

that the plant does not utilize water storage tanks for fire protection. The fire water source is

direct from Lake Ontario. Therefore, the staff determined that the applicant does not require

any AMPs.

The staff also noted from the LRA review that fire hydrants and sprinklers were excluded from

the AMP for the Fire Protection - Water System.

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During the audit and review, the staff discussed this issue with the applicant's fire protection

personnel and asked the applicant why fire hydrants and sprinklers were excluded from the

AMP. The applicant stated that fire hydrants are subject to an AMR and are included in the

component type 'valve body' in LRA Table 3.3.2-5. Sprinkler heads also in LRA Table .3.3.2-5

are subject to an AMR and are included in the component type 'nozzle'. The staff determined

that the applicant's response is acceptable because the fire hydrants and sprinkler heads are

identified in LRA Table 3.3.2-5, subject to an AMR, and adequately managed by the AMP for

the Fire Water System.

During the audit and review, the staff also questioned the applicant concerning a statement in

LRA Section B.1.13.2 that stated "many of these systems are normally maintained at required

operating pressure and monitored." The use of the phrase 'many of these' in the statement

infers that there are some fire water systems that are not normally maintained at required

operating pressures. The applicant stated that deluge, dry pipe and preaction sprinkler systems

are normally dry and will only fill with water when a fire is detected. The fire hose standpipe

located in the motor generator fan room is normally maintained dry due to the potential for

freezing. If needed, the standpipe is filled and pressurized by use of a local valve. The staff

determined that the applicant's response was acceptable because some systems are

maintained dry until activated via fire detection instrumentation or the opening of a manual

valve.

The staff questioned the applicant about the lack of an AMP for the water foam system. In its

response, the applicant stated that the water foam system is a subsystem of the fire water

system and is described in LRA Table 3.3.2 (environment - fire protection foam). Since the

aging effects of the fire protection foam system is more conservative than that of raw water and

the applicant manages the aging effects of this system with the Fire Water System Program

AMP, the staff concluded that the aging effects of the water foam system are adequately

maintained.

The staff finds the applicant's Fire Water System Program acceptable because it conforms to

the recommended GALL AMP XILM27, "Fire Water System," with the exception and

enhancements as described below.

Exception 1. The LRA states an exception to the following GALL Report program element:

Element: 3: parameters monitored/inspected

Exception: NUREG-1 801 specifies that periodic flow testing of the fire water

system is performed using the guidelines of NFPA 25. Under the

JAFNPP program, this test is performed in accordance with

section 11, Chapter 5 of the Fire Protection Handbook, 14t

Edition, published by the National Fire Protection Association.

The LRA states the following note to this exception:

Using of the fire Protection Handbook, 14h Edition, published by the National

Fire Protection Association, is an appropriate application of industry standards to

ensure no loss of function of this system.

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The LRA states that the periodic flow testing of the fire water system is performed in

accordance with the guidelines of Section 11, Chapter 5 of the Fire Protection Handbook

instead of the guidelines of NFPA 25, as recommended by the GALL Report. The staff

reviewed both of these documents and surveillance requirement TRS 3.7.H. 18 of the TRM. The

staff also interviewed the applicant's fire protection engineers. The staff determined that the

extent of the testing requirements, the acceptance criteria and the analysis of the test data

outlined in Section 11, Chapter 5 of the NFPA Fire Protection Handbook followed the guidance

provided in NFPA 25. Overall, staff noted that the NFPA Fire Protection Handbook periodic

water flow testing follows the NFPA 25 recommendations and is adequate to assess the ability

of the system to perform its intended function. Therefore, staff finds this exception acceptable.

Exception 2. The LRA states an exception to the following GALL Report program element:

Element: 4: detection of aging effects

Exception: NUREG - 1801 specifies annual fire hydrant hose hydrostatic test.

However, the hoses are not subject to aging management since

they are periodically inspected, hydrotested, and replaced.

The LRA states the following note to this exception:

Table 2.1-3 of NUREG - 1800 Rev. 1 provides for the exclusion of fire hoses

from aging management review based on their short-lived nature.

During the audit and review, the staff asked the applicant to clarify the CLB for the fire hydrant

tests at JAFNPP.

In its response, the applicant stated that "inspection, testing, and replacement of fire hoses are

conducted in accordance with JAFNPP TRM, Rev. 12, at least once every 18 months (24

months in high radiation areas) and that hydrostatic tests are performed at least once every 36

months (48 months in high radiation areas). As stated in LRA Section 2.1.2.4.4, replacements

occur based on the results of inspections and testing." Also, the applicant stated that the LRA

excluded fire hoses from an AMR since they are periodically inspected, hydro-tested, and

replaced. In LRA Amendment No. 5 dated February 1, 2007 (ML070440127), the applicant

clarified LRA Section B.1.13.2, note 2, to the exception to state" Fire hoses are replaced based

on periodic performance or condition monitoring and are excluded from an AMR per SRP-LR

Table 2.1-3, Revision 1." The staff reviewed the applicant's response and determined that this

exception is acceptable because the applicant meets the requirements specified in TRM

Section 3.7.K and Q for the fire hydrant hose hydrostatic test and the plant-specific operating

experience indicates no aging-related events adversely affecting system operation. The staff

found these frequencies to be reasonable and adequate to manage the aging effects. Also, the

staff determined that since hoses are replaced based on performance or condition monitoring,

this meets the criteria of SRP-LR Section 2.1.3.2.2. The staff is adequately assured that the

hydrostatic test for fire hoses to manage the aging effects will be considered appropriately

during plant aging management activities.

Exception 3. The LRA states an exception to the following GALL Report program element:

Element: 4: detection of aging effects

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Exception: NUREG - 1801 specifies annual gasket inspections. Under the

JAFNPP program, visual inspection, re-racking and replacement

of gaskets in couplings occurs at least once per operating cycle

(every 24 months in high radiation areas).

The LRA states the following note to this exception:

Since aging effects are typically manifested over several years, differences in

inspection and testing frequencies are insignificant.

LRA exception for Detection of Aging Effects Program element states that visual inspection,

re-racking and replacements of gaskets in couplings occurs at least once per operating cycle

(24 months). The GALL Report recommends an annual inspection frequency. During the audit

and review, the staff asked the applicant the basis for the proposed frequency. In its response,

the applicant stated that gaskets in Fire Water components were excluded from Detection of

Aging Effects Program element as an exception to the GALL Report because they are treated

as consumables per the GALL Report guidelines and are not subject to an AMR. In its response

dated February 1, 2007 (Amendment No. 5), the applicant revised the exception to state:

Gaskets are not subject to an AMR since they are periodically inspected, tested

and replaced.

Note 3: Gaskets are replaced based on performance or condition monitoring and

are excluded from aging management review per Table 2.1-3 of NUREG-1800

Rev. 1.

The applicant also stated that the inspection and replacement of gaskets are conducted per

JAFNPP TRM, Revision 12, at least once every 18 months (24 months in high radiation areas).

Also, as stated in LRA Section 2.1.2.4.4, replacements occur based on the results of

inspections and testing. The staff reviewed the applicant's response and determined that the

exception is consistent with TRM Sections 3.7.K and Q. In addition, a review of the operating

experience did not reveal any age-related failures, since gaskets are consumable and

periodically inspected, tested, and replaced. Also, the staff determined that since hoses are

replaced based on performance or condition monitoring, this meets the criteria of SRP-LR

Section 2.1.3.2.2. The staff found these frequencies to be reasonable and adequate to manage

the aging effects.

The applicant's LRA for the Fire Water System Program stated that the following

enhancements:

Enhancement 1. The LRA states an enhancement to the following GALL Report program

elements:

Elements: 3: parameters monitored/inspected

6: acceptance criteria

Enhancement: Procedures will be enhanced to include inspection of hose

reels for corrosion. Acceptance criteria will be enhanced to

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verify no significant corrosion.

The staff found the enhancements to "parameters monitored/inspected," and "acceptance

criteria" program elements to be acceptable because when the enhancements are

implemented, Fire Water System Program will be consistent with GALL AMP XI.M27 and will

adequately manage the effects of aging (Commitment No. 6 (JAFP-06-0109, dated

July 31, 2007)).

Enhancement 2. The LRA states an enhancement to the following GALL Report program

elements:

Elements: 3: parameters monitored/inspected

6: acceptance criteria

Enhancement: Procedures for sprinkler systems will be enhanced to

include visual inspection of spray and sprinkler system

internals for evidence of corrosion. Acceptance criteria will

be enhanced to verify no significant corrosion.

The staff found the enhancements to"parameters monitored/inspected," and "acceptance

criteria" program elements to be acceptable because when the enhancements are

implemented, the Fire Water System Program will be consistent with GALL AMP XI.M27 and

will adequately manage the effects of aging (Commitment No. 6).

Enhancement 3: The LRA states an enhancement to the following GALL Report program

element:

Element: 4: detection of aging effects

Enhancement: A sample of sprinkler heads will be inspected using

guidance of NFPA 25 (2002 Edition) Section 5.3.1.1.1.

NFPA 25 also contains guidance to repeat this sampling

every 10 years after initial field service testing

(Commitment No. 6).

The staff found the enhancements to "detection of aging effects" program element to be

acceptable because when the enhancements are implemented, the Fire Water System

Program will be consistent with GALL AMP XI.M27 and will adequately manage the effects of

aging.

Enhancement 4. The LRA states an enhancement to the following GALL Report program

element:

Element: 4: detection of aging effects

Enhancement: Wall thickness evaluations of fire protection piping will be

performed on system components using non-intrusive

techniques (e.g., volumetric testing) to identify evidence of

loss of material due to corrosion. These inspections will be

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performed before the end of the current operating term

and at intervals thereafter during the period of extended

operation. Results of the initial evaluations will be used to

determine the appropriate inspection interval to ensure

aging effects are identified prior to loss of intended

function (Commitment No. 6).

The staff found the enhancements to "detection of aging effects" program element to be

acceptable because when the enhancements are implemented, the Fire Water System

Program will be consistent with GALL AMP XI.M27 and will adequately manage the effects of

aging.

ý.Operatinq Experience. LRA Section B.1.13.2 states that visual inspections of fire hose station

equipment in October 2005 detected no loss of material on steel parts. In the past, fire hose

station angle valves have been replaced due to corrosion. Detection of degradation and

corrective action prior to loss of intended function prove that the program is effective for

managing aging effects for steel fire water system components. Full-flow tests of fire main

segments and hydrant inspections from 2003 through 2005 found no evidence of obstruction or

loss of material. Spray and sprinkler system functional tests and visual inspections of piping and

nozzles from 2004 through 2006 found no evidence of blockage or loss of material, proving that

the program is effective for managing loss of material for fire water system components. QA

audits and surveillances in 2002 and 2003 revealed that the material condition of system

equipment was good and met licensing requirements. The audits and surveillances revealed no

issues or findings with impact on program effectiveness to manage aging effects for fire

protection components. In March 2005, NRC completed a triennial fire protection team

inspection to assess whether the plant had implemented an adequate fire protection program

and whether post-fire safe shutdown capabilities had been established and properly maintained.

Results confirmed that plant personnel had maintained the fire protection systems in

accordance with their fire protection program, identified program deficiencies, and implemented

appropriate corrective actions. The team also reviewed fire detection and suppression

surveillance procedures and concluded-that plant personnel had maintained passive features in

a state of readiness.

The staff reviewed the operating experience review results and confirmed that the plant-specific

operating experience did not include any aging effects for systems and components within the

scope of this program that are not bounded by industry operating experience. The staff noted

that none of the condition reports identified as aging-related involved components related to the

Fire Water system.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR SuDplement. In LRA Section A.2.1.14, the applicant provided the UFSAR supplement

for the Fire Water System Program. The staff determined during its review of the Fire Water

System Program that the enhancement for revising procedures to include inspections of hose

reels for corrosion is not addressed in Appendix A. For additional clarification the applicant

stated that LRA Appendix A will be revised. In its response dated February 1, 2007, the

applicant submitted Amendment 5 to the LRA which added the program enhancements to LRA

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Section A.2.1.14, "Fire Water System Program."

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program,

the staff finds those program elements, for which the applicant claimed consistency with the

GALL Report are consistent. In addition, the staff reviewed the exceptions and the associated

justifications, and determined that the AMP, with the exceptions, is adequate to manage the

aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed

that the implementation of the enhancements prior to the period of extended operation would

result in the existing AMP being consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.13 Metal-Enclosed Bus Inspection Program

Summary of Technical Information in the Application. LRA Section B. 1.17 describes the new

Metal-Enclosed Bus Inspection Program as consistent, with exception, with GALL AMP XI.E4,

"Metal Enclosed Bus."

Under the Metal-Enclosed Bus Inspection Program, internal portions of the non-segregated

phase bus T2Y and T3Y components will be inspected for cracks, corrosion, foreign debris,

excessive dust buildup, and evidence of water intrusion. Bus insulation will be inspected for

signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate

overheating or aging degradation. Internal bus supports will be inspected for structural integrity

and signs of cracks. Bolted connections are covered with heat-shrink tape or insulating boots

per manufacturer's recommendations, so a sample of accessible bolted connections will be

visually inspected for insulation material surface anomalies. Enclosure assemblies will be

visually inspected for evidence of loss of material and, where appropriate, enclosure assembly

elastomers will be visually inspected and manually flexed to manage cracking and change in

material properties. The program will be implemented fully prior to the period of extended

operation.

Staff Evaluation. During its audit and review, the staff reviewed exception to determine whether

the AMP, with the exception, remains adequate to manage the aging effects for which it is

credited.

The staff interviewed the applicant's technical staff and reviewed the Metal-Enclosed Bus

Inspection Program bases documents. Specifically, the staff reviewed the program elements

and associated bases documents to determine consistency with GALL AMP XI.E4.

During the audit and review, the staff noted that LRA Section B.1.17 states that "where

applicable, enclosure assembly elastomers will be visually inspected and manually flexed to

manage cracking and change in material properties." The GALL Report recommends inspecting

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the elastomers. The staff requested the applicant to clarify it intended to inspect the enclosure

assembly elastomer and if it did, remove the phrase "as applicable" and if it did not, provide a

justification of why the elastomer is not subject to aging.

In its response, the applicant stated that enclosure assembly elastomers will be inspected. The

applicant would revise the LRA and program basis document to remove the wording "where

applicable." In its response dated February 1, 2007, the applicant revised LRA Section B.1.17

to reflect this change.

Section 54.4(a)(3) of 10 CFR requires that "All systems, structures, and components relied on

in safety analyses or plant evaluation to perform function that demonstrate compliance with the

Commission's regulation for station blackout (10 CFR 50.63)" be included within the scope of

license renewal. The staff noted that-JAFNPP UpdatedFinal Safety Evaluation Report (UFSAR)

Section 8.2.1 states that "an alternate source of ac power, from the 345 kilo-volt (kV) system is

available to provide power to plant auxiliaries during plant shutdown. The power is supplied to

plant 4.16kV emergency buses by back feeding from the 345kV system via main transformer,

isolated phase bus duct, and the normal station service transformer." Since back feeding is

identified as a qualified alternate source for restoration of ac power to 4.16kV safety buses, the

staff requested the applicant to provide a technical justification for why the alternate ac source

to 4.16kV safety buses from the 345kV system is not included within the scope of license

renewal and does not need an AMP.

In its response, the applicant stated that:

The three sources of normal ac power for JAFNPP are the normal, reserve, and

emergency sources. The normal source is the Normal Service Station

Transformer (NSST) 71T-4. The reserve source is the Reserve Service Station

Transformers (RSST)-2 and 71T-3. The emergency source is the emergency

diesel generators. In UFSAR Section 8.3, the 115kV system has the safety

objective to provide a supply of offsite power for the engineered safeguard loads.

The 115kV system has the power generation objective to provide two sources of

offsite ac power to the plant service ac power distribution system for plant

startup, operating and shutdown power including adequate power to the

emergency service buses for the safe shutdown of the reactor. The 115kV bus at

JAFNPP is energized from two 115kV transmission lines as shown in UFSAR

Figure 8.3-2. This provides the General Design Criteria (GDC)-17 criteria for the

RSST. Section 8.11 of the UFSAR addresses Station Black Out (SBO). SBO is

defined in 10 CFR 50.2 as a complete loss of ac electric power to essential and

non-essential switchgear buses. Offsite power is assumed to be lost concurrently

with a main turbine trip and unavailability of the on-site emergency ac power

system. SBO does not include loss of ac power to buses fed by the station

batteries through inverters and does not assume a concurrent single failure or

design basis accident. Section 8.2.1 of the UFSAR, states that "an alternate

source of ac power, from the 345kV system, is available to provide power to

plant auxiliaries during plant shutdown. The power is supplied to plant 4.16kV

buses by back feeding from the 345kV system via main transformers, isolated

phase bus duct, and the NSST. The main generator is isolated by removing the

isolated phase bus duct disconnect links." This alternate source is only used

during outages for maintenance on the RSST. This source of offsite ac power is

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not credited for recovery from SBO. The two sources of offsite ac power is the

two independent 115kV lines that feed the RSST. There is a cross feed circuit

that can be closed to provide power to both of the 4.16kV safety buses in the

plant in the case of loss of one 115kV line. This cross-tie can be closed in less

than ten minutes when needed. This source will be much faster than installing

the feedback source which take at least 12 hours. No other source is needed or

required.

The staff finds the applicant's response and assessment acceptable because back feeding

from 345kV is not credited for SBO offsite recovery. The two 115kV buses which are energized

from independent 115kV transmission lines provide power to the 4.16kV safety buses during

startup, shutdown, and SBO recovery. There is also a cross feed circuit that can be closed to

provide power of both of the 4.16kV safety buses in the case of loss of one 115kV line. An

alternate source of ac power back feeding from the 345kV system is not credited for SBO

offsite recovery and therefore, an AMP is not required.

The staff concludes that the applicant's Metal-Enclosed Bus Inspection Program provides

assurance that aging effects of metal enclosed bus caused by cracked insulation, moisture,

debris in the bus enclosure, and loosening of bolted connections will be managed consistent

with CLB during the period of extended operation. The staff finds the applicant's

Metal-Enclosed Bus Inspection Program acceptable because it conforms to the recommended

GALL AMP XI.E4, "Metal-Enclosed Bus," with an exception as described below.

Exception. The LRA states an exception to the following GALL Report program elements:

Elements: 3: parameters monitored/inspected

4: detection of aging effects

Exception: MEB enclosure assemblies will be inspected under this program

instead of underthe Structure Monitoring Program.

The applicant stated in the LRA, under Exception Note 1, that inspection of MEB enclosure

under the Metal-Enclosure Bus Inspection Program assures that effects of aging will be

identified prior to loss of intended functions.

GALL Report, Revision 1, Section VI, Items VI.A-12 and VI-13) refers to the Structure

Monitoring Program for inspecting the external of MEB for loss of material due to general

corrosion and inspecting the enclosure seals for hardening and loss of strength due to

elastomers degradation. In LRA, Section B.1.17, the applicant stated that the program attribute

of MEB inspection program would be consistent with the program attribute in GALL Report

Section XI.E4, with an exception. The exception is to inspect MEB enclosure assemblies in

addition to internal surfaces using the MEB inspection program. The staff found the exception

acceptable because external of MEB and enclosure seals will be inspected in the MEB

Inspection program. These inspections are consistent with the GALL Structure Monitoring

Program.

Operating Experience. LRA Section B.1.17 states that the Metal-Enclosed Bus Inspection

Program is a new program. Industry operating experience will be considered in the

development of this program. Industry operating experience that forms the basis for the

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program is described in the operating experience element of the GALL Report program

description. Plant-specific operating experience is consistent with the operating experience in

the GALL Report program description. This program will provide reasonable assurance of

management of aging effects so that components will continue to perform their intended

functions consistently with the CLB for the period of extend operation. With additional operating

experience, lessons learned can be used to adjust the program as needed.

The staff also interviewed the applicant's technical staff and also reviewed the operating

experience reports and confirmed that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.19, the applicant provided the UFSAR supplement

for the Metal-Enclosed Bus Inspection Program. The staff reviewed the applicant's license

renewal commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1,

2007, and confirmed that this new program is identified as Commitment No. 8 (JAFP-06-0109,

dated July 31, 2006) to be implemented before the period of extended operation.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Metal-Enclosed Bus

Inspection Program, the staff finds those program elements, for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception

and the associated justifications, and determined that the AMP, with the exception, is adequate

to manage the aging effects for which it is credited. The staff concludes that the applicant will

have a program 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).

3.0.3.2.14 Oil Analysis Program

Summary of Technical Information in the Application. LRA Section B.1.20 describes the existing

Oil Analysis Program as consistent, with exception and enhancements, with GALL

AMP XI.M39, "Lubricating Oil Analysis."

The Oil Analysis Program maintains oil systems free of contaminants to preserve an

environment not conducive to loss of material, cracking, or fouling. Sampling frequencies are

based on vendor recommendations, accessibility during plant operation, equipment importance

to plant operation, and previous test results.

Staff Evaluation. During its audit and review, the staff reviewed the exception and

enhancements to determine whether the AMP, with the exception and enhancements, remains

adequate to manage the aging effects for which it is credited.

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The staff interviewed the applicant's technical staff and reviewed the Oil Analysis Program

bases documents. Specifically, the staff reviewed the program elements and associated bases

documents to determine consistency with GALL AMP XI.M39.

The staff finds the applicant's Oil Analysis Program acceptable because it conforms to the

recommended GALL AMP XI.M39, "Oil Analysis Program," with the exception and

enhancements as described below.

Exception. The LRA states an exception to the following GALL Report program element:

Element: parameters monitored/inspected

Exception: flash point is not determined for sampled oil.

The applicant's note on this exception provides the following clarifications:

Analyses of filter residue or particle count, viscosity, total acid/base

(neutralization number), water content, and metals content provide sufficient

information to verify the oil is suitable for continued used.

During the audit and review, the staff questioned the applicant concerning the basis for the

exception to the GALL Report for the flash point determination of industrial lubricants used in

components subject to hydrocarbon buildup that do not have regular oil changes. The aging

management component in this category at JAFNPP is the diesel fire pump engine. The staff

reviewed maintenance and chemistry documents for this component. This review revealed that

a flash point reading of the engine lubricant is taken annually with an engine oil change of every

six years. The lubricating oil in the engines of the security backup generator and the emergency

diesel generator are changed on a regular basis and do not fall within the guidelines of this

section of the GALL Report. This issue was discussed with the applicant's technical staff and

the applicant committed to amending the LRA to remove this exception. In its response dated

February 1, 2007, the applicant revised the LRA Section B. 1.20 to delete this exception. The

staff finds the applicant's action acceptable because flash point is determined for sampled oil as

described in the GALL Report and the applicant is not taking any exceptions to GALL

AMP XI.M39.

The applicant stated in LRA that the following enhancements will be implemented in meeting

the GALL Report program elements prior to the period of extended operation and these

enhancements are identified as Commitment No. 5 in LRA Amendment 5, dated February 1,

2007:

Enhancement 1. The LRA states an enhancement to the following GALL Report program

element:

Element: 1: scope of program

Enhancement: The Oil Analysis Program guidance documents will be

enhanced to periodically sample lubricating oil in the

security generator, the fire pump diesel, as well as the oil

internal to the underground oil filled cable.

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The staff found this enhancement acceptable because when enhancements are implemented,

the Oil Analysis Program, "scope of program" program element will be consistent with GALL

AMP XI.M39 and provide additional assurance that the effects of aging will be adequately

managed (Commitment No. 11 (JAFP-06-0109, dated July 31, 2007).

Enhancement 2, The LRA states an enhancement to the following GALL Report program

element:

Element: 3: parameters monitored/inspected

Enhancement: The Oil Analysis Program guidance documents will be

enhanced to include viscosity and neutralization number

determination of oil samples from components that do not

have regular oil changes.

The staff found this enhancement acceptable because when enhancements are implemented,

the Oil Analysis Program, " parameters monitored/inspected" program element will be

consistent with GALL AMP XI.M39 and provide additional assurance that the effects of aging

will be adequately managed (Commitment No.11).

Enhancement 3. The LRA states an enhancement to the following GALL Report program

element:

Element: 3: parameters monitored/inspected

Enhancement: The Oil Analysis Program guidance documents will be

enhanced to include particulate and water content for oil

replaced periodically.

The staff found this enhancement acceptable because when enhancements are implemented,

the Oil Analysis Program, "parameters monitored/inspected" program element will be consistent

with GALL AMP XI.M39 and provide additional assurance that the effects of aging will be

adequately managed (Commitment No. 11).

Operating Experience. LRA Section B.1.20 states that the high-pressure coolant injection

(HPCI) lube oil sump suffered from water intrusion from March 2001 until February 2005

because valve 23MOV-14 was inadequate for steam service. During that time, the oil was

monitored monthly and water was drained from the oil sump as necessary to keep the system

as water-free as possible. Results of particle count, viscosity, and additive metal depletion

analyses found no evidence of water, emulsion, or contaminant carry-over to the operating oil

system. Recent quarterly sampling results show water and particulates within acceptance

criteria. In 2004, a few non-magnetic metallic wear particles were found on the EDG "D" lube oil

filter screens. The quantity was not large enough for elemental analysis of material

composition. EDG "D" oil sample particle counts at the time were in the normal range, indicating

that particles had been captured in the 40 mesh filters and not entered the operating oil system.

Corrective action was taken to schedule filter inspections during subsequent diesel

maintenance activities to capture particles for analysis to determine material composition and

possible sources. Continuous confirmation of oil quality and timely corrective actions prove that

the program is effective in managing aging effects for lube oil components.

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The staff reviewed operating experience reports and confirmed that the plant-specific operating

experience did not include any aging effects for systems and components within the scope of

this program that are not bounded by industry operating experience. The staff also reviewed

four condition reports for the Oil Analysis Program. These reports addressed the operating

experience problems with HPCI lube oil sump water intrusion and metallic wear particles found

on the EDG D lube oil filter screen. In cases where contaminant levels were exceeded,

corrective actions included resampling or replacement of lube oil and/or filter and increased

frequency of surveillance. The staff determined that the applicant took appropriate corrective

actions to prevent and correct these problems.

On the basis of its review of the operating experience and discussions with the applicant's

technical staff, the staff concludes that the applicant's Oil Analysis Program will adequately

.manage the aging effects identified in the LRA for which this AMP is credited.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.22, the applicant provided the UFSAR supplement

for the Oil Analysis Program. The staff reviewed the applicant's license renewal commitment list

in LRA Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and confirmed that

the program enhancements are identified as Commitment No. 11 to be implemented before the

period of extended operation.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Oil Analysis Program, the

staff finds those program elements, for which the applicant claimed consistency with the GALL

Report are consistent. In addition, the staff reviewed the enhancements and confirmed that the

implementation of the enhancements prior to the period of extended operation would result in

the existing AMP being consistent with the GALL AMP to which it was compared. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.15 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. LRA Section B.1.23 describes the

Reactor Head Closure Studs Program as an existing program that is consistent, with the

program attributes of GALL AMP XI.M3, "Reactor Head Closure Studs," with one exception.

The applicant stated that this program includes ISI per the requirements of ASME Section XI,

Subsection IWB, and preventive measures (e.g. rust inhibitors, stable lubricants, appropriate

materials) to mitigate cracking and loss of material of reactor head closure studs, nuts,

washers, and bushings.

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Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the Reactor Closure Head

Studs Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M3.

With the exception discussed and evaluated below, the staff finds the applicant's program

includes all ASME Code, Section XI inspection requirements for the RV closure studs and

closure flange and is consistent with the additional recommendation provided in the GALL

Report for the. RV closure flange assembly, including the studs, flange, nuts, bushings, and

washers.

The staff finds the applicant's Program acceptable because it conforms to the recommended

GALL AMP XI.M3, "Reactor Head Closure Studs," with the exception as described below.

Exception. The LRA states an exception to the GALL Report program element "detection of

aging effects." Specifically, the exception states:

When reactor head closure studs are removed for examination, either a surface

or volumetric examination is allowed.

The staff noted that the applicant entered the 40 10-Year ISI Interval for JAFNPP in

January 2007. The applicant was required by 10 CFR 50.55a(g)(4)(I) to update the ASME

Code, Section XI (Section XI code of record) to the 2001 Edition of Section XI, inclusive of the

2003 Addenda. The staff requested confirmation from the applicant that the Section XI code of

record for the 4h 10-Year ISI Interval-is the 2001 Edition of Section XI, inclusive of the 2003

Addenda. The applicant clarified in its response that the exception in this AMP on the

Section XI code edition is applicable to the 3rd 10-Year ISI Interval for JAFNPP. The applicant

also clarified that the new Section XI Code of record for the 4h 10-Year ISI Interval is the 2001

Edition of Section XI, inclusive of the 2003 Addenda. The applicant stated that the LRA will be

amended to indicate that the 2001 Edition of Section XI, inclusive of the 2003 Addenda is the

applicable edition of Section XI. The applicant amended the LRA in Amendment No. 5, dated

February 1, 2007.

The Section XI, Examination Category B-G-1, Inspection Item B6.30 provides the

10-Year Interval ISI requirements for inspecting the RV closure studs when the studs are

removed. In the 2001 Edition of Section XI, inclusive of the 2003 Addenda, Inspection B6.30

requires either a volumetric examination or surface examination of all of the closure studs each

10-Year ISI Interval. The 4h 10-Year ISI Interval for JAFNPP will be the 10-Year interval in

effect if the LRA for JAFNPP is approved by the staff. In its exception to the GALL Report, the

applicant has proposed to perform either a volumetric examination or a surface examination of

the RV closure studs when they are removed. This is in compliance with the requirements of

Inspection Item B6.30 in the 2001 Edition of Section XI, which is the edition of record required

for JAFNPP's 4' 10-Year ISI Interval.

Based on this assessment, the staff concludes that the exception taken by the applicant on

examination of the RV closure studs in the removed status for the studs is acceptable because

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the inspection requirements are in compliance with the requirements of Examination Category

B-G-1, Inspection Item B6.30 in the 2001 Edition of Section XI.

Operating Experience. LRA Section B. 1.23 states that volumetric examination of 30 reactor

head closure studs in 1990 recorded no indications. Absence of recordable indications proves

that the program is effective for managing loss of material and cracking of the reactor head

closure studs, nuts, and washers

The staff interviewed the applicant's personnel and reviewed operating experience reports and

confirmed that the plant-specific operating experience did not include any aging effects for

components within the scope of this program that are not bounded by industry operating

experience. A review of the condition reports shows that cracking of the head studs from stress

corrosion cracking (SCC), IGSCC, and loss of material due to wear has not occurred. The staff

also confirmed that the 2006 refueling outage reactor head closure studs examinations did not

identify any indications.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.25, the applicant provided the summary description

for the Reactor Head Closure Studs Program. The staff reviewed LRA Section A.2.1.25 and

compared it to the corresponding UFSAR Supplement description for Reactor Head Closure

Stud Programs in SRP-LR Table 3.1-2.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and the

associated justifications, and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.16 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. The applicant provided the following

description of the Reactor Pressure Vessel AMP in LRA Section B.1.24:

Program Description

The Reactor Vessel Surveillance Program complies with the guidelines for an

acceptable Integrated Surveillance Program as described in NUREG-1801,

Section XI.M31, Reactor Vessel Surveillance. This program manages reduction

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in fracture toughness of reactor vessel beltline materials to assure that the

pressure boundary function of the reactor pressure vessel is maintained for the

period of extended operation.

JAFNPP has applied to use the BWR (boiling-water reactor) vessel and internals

project (BWRVIP) Integrated Surveillance Program (ISP) and expects staff

approval well before the period of extended operation. The Reactor Vessel

Surveillance Program monitors changes in the fracture toughness properties of

ferritic materials in the reactor pressure vessel (RPV) beltline region. As

BWRVIP-ISP capsule test reports become available for RPV materials

representative of JAFNPP, the actual shift in the reference temperature for nil

ductility transition of the vessel material may be updated. In accordance with

10 CFR 50 Appendices G and H, JAFNPP reviews relevant-test reports to

assure compliance with fracture toughness requirements and

pressure-temperature limits. BWRVIP-1 16, "BWR Vessel and Internals Project

Integrated Surveillance Program (ISP) Implementation for License Renewal,"

describes the design and implementation of the ISP during the period of

extended operation. BWRVIP-1 16 identifies additional capsules, their withdrawal

schedule, and contingencies to ensure that the requirements of 10 CFR 50

Appendix H are met for the period of extended operation.

NUREG-1801 Consistency

The Reactor Vessel Surveillance Program at JAFNPP is consistent with the

program described in NUREG-1 801, Section XI.M31, Reactor Vessel

Surveillance, with one enhancement.

Exceptions to NUREG-1801

None.

Enhancements

The following enhancement will be fully implemented prior to the period of

extended operation.

Attributes Affected Enhancement

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5. Monitoring and Trending Actions The Reactor Vessel Surveillance Program

6. Acceptance Criteria will be enhanced to proceduralize the data

7. Corrective Actions analysis, acceptance criteria, and corrective

actions described in this program

description, to meet the requirements of the

ISP as found in BWRVIP-86-A, 102,116,

and 135.

Operating Experience

JAFNPP has committed to the Boiling Water Reactor Vessel and Internals

Project (BWRVIP) Integrated Surveillance Program (ISP). The fact that the plant

participates in the BWRVIP ISP ensures that future OE from all participating

BWRs will be factored into this program. Thus, the Reactor Vessel Surveillance

Program provides reasonable assurance that the effects of aging will be

managed such that the applicable components will continue to perform their

intended functions consistent with the current licensing basis for the period of

extended operation.

Conclusion

The Reactor Vessel Surveillance Program provides reasonable assurance that

aging effects will be managed such that applicable components will continue to

perform their intended functions consistent with the current licensing basis for

the period of extended operation.

Staff Evaluation. In LRA Section B.1.24, the applicant described its AMP to manage irradiation

embrittlement of the RPV through testing that monitors RPV beltline materials. The LRA stated

that the RPV surveillance program will be enhanced by making it consistent with the BWRVIP

ISP for periods of extended operation prior to the JAFNPP entering its period of extended

operation.

In RAI B.1.24-3 dated January 12, 2007, the staff requested that the applicant provide

information on whether it is currently implementing the BWRVIP ISP at JAFNPP. If so, the

applicant was asked to reference the staff-approved license amendment request for

implementing the ISP at JAFNPP.

In its response dated January 12, 2007, the applicant stated that it has implemented the

BWRVIP ISP which is based on the BWRVIP-78 report, "BWR Integrated Surveillance Program

Plan," and the BWRVIP-86-A report, "BWR Vessel and Internals Project, BWR Integrated

Surveillance Program Implementation." These reports are consistent with the GALL

AMP XI.M31, "Reactor Vessel Surveillance," for the period of the current JAFNPP license. The

staff concluded that the BWRVIP ISP in the BWRVIP-78 and BWRVIP-86-A reports is

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acceptable for BWR licensee implementation, provided that all participating licensees use one

or more compatible neutron fluence methodologies acceptable to the staff when determining

surveillance capsule and RPV neutron fluences.

In its response dated February 12, 2007, the applicant stated that the staffs final safety

evaluation, dated July 26, 2006, for TS Amendment #285 was the staff's SE for accepting the

BWRVIP ISP for the current term at JAFNPP. The staff has identified this as a sub Open Item

(sOl) for Open Item 4.2.1-1 which will be further discussed in SER Section 4.0.

The BWRVIP developed an updated version of the ISP which is documented in the

BWRVIP-1 16 report. The report provides guidelines for an ISP to monitor neutron irradiation

embrittlement of the RPV beltline materials for all U.S. BWR power plants for the license

renewal period. The applicant stated in LRA Section B.1.24, and in the UFSAR

Section A.2.1.26, "Reactor Vessel Surveillance Program,"' that it will implement the ISP

specified in the BWRVIP-1 16 report. The staff reviewed UFSAR Section A.2.1.26 to determine

whether it provides an adequate description of the program.

In RAI B.1.24-1 dated January 12, 2007, the staff requested that the applicant make the

following commitment in LRA Section B. 1.24 and in LRA Section A.2.1.26:

The BWRVIP-1 16 report which was approved by the staff will be implemented at

JAFNPP with the conditions documented in Sections 3 and 4 of the staff's final

SE for the BWRVIP-1 16 report dated March 1, 2006.

In its response dated February 12, 2007, the applicant stated that UFSAR Section A.2.1.26 and

LRA Section B.1.24 are being updated to include the aforementioned commitment proposed by

the staff.

Based on its review, the staff finds the applicant's response to RAI B.1.24-1 acceptable.

Therefore, the staff's concern described in RAI B.1.24-1 is resolved.

Part 50 of 10 CFR, Appendix H, requires that an ISP used as a basis for a facility's RPV

.surveillance program be reviewed and approved by the staff. The ISP to be used by the

applicant is a program that was developed by the BWRVIP and the applicant will apply the

BWRVIP ISP as the method by which the JAFNPP will comply with the requirements of

10 CFR Part 50, Appendix H. The BWRVIP ISP identifies capsules that must be tested to

monitor neutron radiation embrittlement for all licensees participating in the ISP and identifies

capsules that need not be tested (standby capsules). The BWRVIP-1 16 report, Table 3.3,

indicates that the remaining capsule from JAFNPP is not to be tested. This untested capsule

was originally part of the applicant's plant-specific surveillance program and has received

significant amounts of neutron radiation.

In RAI B.1.24-2 dated January 12, 2007, the staff requested that the applicant include the

following commitment in LRA Section A.2.1.26:

If the JAFNPP standby capsule is removed from the RPV without the intent to

test it, the capsule will be stored in manner which maintains it in a condition

which would permit its future use, including during the period of extended

operation, if necessary.

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In its response dated February 12, 2007, the applicant stated that the staff's aforementioned

commitment is being incorporated in LRA Section A.2.1.26.

Based on its review, the staff finds the applicant's response to RAI B.1.24-2 acceptable.

Therefore, the staffs concern described in RAI B.1.24-2 is resolved.

By letter dated November 5, 2007, the applicant submitted its new calculations for the neutron

fluence values, which was based on the fluence values in LRA Section 4.2.1. As described in

SER Section 4.2.1.2, the staff reviewed and accepted the applicant's new methodology that

was used for calculating the neutron fluence values. The staff found that the newly calculated

neutron fluence values remain bounded by the values that were submitted in the applicant's

original LRA. Therefore, the applicant's implementation of the Integrated Surveillance Program

(ISP), as specified in the BWRVIP-1 16 Report, remains valid and as such, the various attributes

in the ISP are not affected by the new methodology of calculating the neutron fluence values.

On the basis of its review, the staff finds that the applicant has demonstrated that the effects of

aging due to loss of fracture toughness of the RPV beltline region 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). Based on this, the staff concludes that

the previously identified sOl B.1.24-3 as described in the SER With Open Items issued on

July 31, 2007, is now closed.

Operatinq Experience. LRA Section B.1.24 states a commitment to the BWRVIP ISP.

Participation in the BWRVIP ISP will factor future operating experience from all participating

BWRs into this program. Thus, the Reactor Vessel Surveillance Program provides reasonable

assurance of management of the aging effects so that components will continue to perform

their intended functions consistently with the CLB for the period of extended operation.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. The applicant described the reactor materials surveillance program as an

existing program in LRA Section A.2.1.26. The program uses periodic testing of metallurgical

surveillance samples to monitor the loss of fracture toughness of the RPV beltline region

materials consistent with the requirements of 10 CFR Part 50, Appendix H. The applicant

further stated that it will implement the staff-approved BWRVIP-1 16 report for the license

renewal period. The BWRVIP-1 16 report was approved by the staff and, as described in the

staff evaluation section, the applicant made a commitment to include the following statement in

the LRA Section A.2.1.26:

The BWRVIP-1 16 report which was approved by the staff will be implemented at

JAFNPP with the conditions documented in Sections 3 and 4 of the staffs final

SE dated March 1, 2006, for the BWRVIP-1 16 report.

As to the status of the remaining JAFNPP standby capsule, the applicant made a commitment

to incorporate the following statement in the LRA Section A.2.1.26:

If the JAFNPP standby capsule is removed from the RPV without the intent to

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test it, the capsule will be stored in manner which would permit its future use, if

necessary.

The staff reviewed the applicant's proposed revision to UFSAR Section A.2.1.26 and

determined that by implementing the most recent staff-approved version of the BWRVIP-1 16

report, the applicant demonstrated its compliance with the requirements of

10 CFR Part 50, Appendix H.

The staffs review determined that the following license condition will be required to ensure that

changes in the withdrawal schedule for the capsule specified in the BWRVIP-1 16 report will be

submitted for staff review and approval.

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

changes to storage requirements must be approved by the NRC, as required by

10 CFR Part 50, Appendix H.

The staff concluded that the information provided in the UFSAR Supplement for the aging

management of systems and components discussed above is equivalent to the information in

the GALL Report and therefore provides an adequate summary of program activities as

required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance Program,

the staff determined that those program elements for which the applicant claimed consistency

with the GALL Report are consistent with the GALL Report. Also, the staff reviewed the

enhancement and confirmed that implementation of the enhancement prior to the period of

extended operation would result in consistency between the existing AMP and the GALL AMP

to which it was compared.

The staff concluded that the applicant had 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). Based on this, the

staff concludes that the previously identified sol B.1.24-3 as described in the SER With Open

Items issued on July 31, 2007, is now closed. The staff also reviewed the UFSAR supplement

A.2.1.26 for this AMP and concluded that it provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

3.0.3.2.17 Service Water Integrity Program

Summary of Technical Information in the Application. LRA Section B.1.26 describes the existing

Service Water Integrity Program as consistent, with exception, with GALL AMP XI.M20,

"Open-Cycle Cooling Water System."

This Service Water Integrity Program relies on implementation of the recommendations of

GL 89-13 to manage the aging effects on the service water system (SWS) for the period of

extended operation. The SWS includes the normal service water, emergency service water

(ESW), and residual heat removal service water (RHRSW). The program inspects components

for erosion, corrosion, and blockage and monitors performance to verify the heat transfer

capability of the safety-related heat exchangers cooled by service water. Chemical treatment

with biocides and chlorine and periodic cleaning and flushing of redundant or infrequently used

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loops control or prevent fouling within the heat exchangers and loss of material in service water

components.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the Service Water Integrity

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.M20.

The staff determined that this program implements the recommendations from GL 89-13 to

manage aging effects in the SWSs. Components within the scope of this program are inspected

for erosion, corrosion, and blockage. Performance testing of heat exchangers within the scope

of this program is carried out to verify acceptable performance. In addition, chemical treatment

with biocides and chlorine is performed, along with periodic cleaning and flushing of redundant

or infrequently used loops, to control or prevent fouling within the heat exchangers and loss of

material in service water components. The staff finds that these activities are consistent with

the recommendations in GALL AMP XI.M20, and are acceptable.

The staff reviewed the applicant's Raw Water Systems Program Plan which identifies the

various program activities conducted on the applicant's raw water and SWSs associated with

the implementation of the applicant's GL 89-13 commitments to the staff. The ongoing

programmatic activities implementing the applicant's GL 89-13 commitments include: biofouling

controls such as, monitoring and inspections, chlorine injection, chemical treatments to control

Microbiologically Influenced Corrosion (MIC), a Zebra Mussel Control Program, and molluscide

treatments; a heat exchanger testing program; and an inspection and maintenance program.

The staff finds that the applicant's GL 89-13 implementation program and activities are in

accordance with GL 89-13 and are consistent with GALL AMP XI.M20.

The staff finds the applicant's Service Water Integrity Program acceptable because it is

consistent with the recommended GALL AMP XI.M20, "Open-Cycle Cooling Water System,"

with an exception as described:

Exception. The LRA states an exception to the GALL Report program element "preventive

actions." Specifically, the exception state:

NUREG-1 801 states that system components are lined or coated. Components

are lined or coated only where necessary to protect the underlying metal

surfaces.

During the audit and review, the staff asked the applicant to provide additional information

regarding the components that are lined or coated, and how aging of these linings is managed.

In its response, the applicant stated that there are no linings or coatings used within the service

water piping. However, as described in the design basis document for SWSs, the use of

appropriate materials is controlled by design processes which consider the environment and

operating experience to ensure appropriate materials are selected. It also includes an example

of service water components that were modified to include protective coatings. These coatings

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are not credited to prevent or minimize aging effects on components and, as such, the AMP

does not identify components that are lined or coated, nor are specific linings or coating

inspections needed.

The applicant further stated that the service water integrity AMP includes visual inspections and

non-destructive testing methods, including ultrasonic testing and eddy current testing of heat

exchanger tubes. Unlined/uncoated components in the SWS are inspected as part of this

program to ensure that aging effects do not affect their ability to perform their intended

functions. The use of appropriate materials is controlled by design processes which consider

the environment and operating experience to ensure appropriate materials are selected.

The staff determined that the applicant's Service Water Integrity Program, in accordance with

GL 89-13, includes a condition and performance monitoring program which inspects

components for erosion, corrosion, and blockage and verifies the heat transfer capability of the

safety-related heat exchangers cooled by service water. Chemical treatment using biocides and

chlorine and periodic cleaning and flushing of redundant or infrequently used loops are used to

control or prevent fouling within the heat exchangers and loss of material in service water

components. The staff finds that the applicant is taking measures with inspections and chemical

treatments under the Service Water Integrity Program to compensate for the SWS components

which in general, do not have internal protective linings or coatings. On this basis, the staff finds

this exception acceptable.

Operating Experience. LRA Section B. 1.26 states that during 2000 and early 2001,

ESW-cooled heat exchangers did not meet target flow rates due to accumulation of silt and

ferrous oxide. Thermal performance testing verified the ability of the coolers to perform as

required under accident conditions. When testing detected degraded thermal performance by

several coolers, an action plan was developed. Corrective actions were implemented to

chemically clean the ESW supply lines; clean the crescent area unit coolers; and vent, drain,

and flush ESW unit coolers and piping. Detection of degradation and corrective action prior to

loss of intended function prove that the program is effective for managing fouling of SWS

components. The results in 2005 from tests of the RHR and ESW cooled heat exchangers

showed them capable of removing the required amount of heat, proving that the program is

effective for managing fouling of SWS components. Eddy current testing of EDG jacket water

coolers in 2004 (EDG-D) and 2005 (EDG-A, B, and C) detected pitting in some of the tubes but

not degradation sufficient to require tube plugging. None of the inspected tubes was blocked by

debris or deposits and the tubes appeared to be very clean. The tubesheets were in good

condition and there was no evidence of degradation of the tube to tubesheet joints. Absence of

degradation proves that the program is effective for managing loss of material for SWS

components.

Results of SWS visual and other nondestructive examinations (2000 to 2004) detected areas of

erosion and corrosion on internal and external surfaces. Corrective actions included

replacement of RHRSW pumps, replacement of ESW and normal service water piping

components, replacement of EDG jacket water heat exchangers, and close monitoring of

RHRSW and ESW pump discharge strainer housings by ultrasonic inspections with repair as

needed. Detection of degradation and corrective action prior to loss of intended function prove

that the program is effective for managing loss of material for SWS components. A two-week

ESW system assessment in February 2000 detected weaknesses in the Service Water Integrity

Program. Corrective actions were taken to re-constitute the licensing commitments of

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GL 89-13, update plant procedures to reflect GL 89-13 commitments, and update the program

manual. Significant improvements addressing lack of program ownership, weak program

maintenance and monitoring, and deficient knowledge and skills were also made. Detection of

program weakness and corrective action prove that the program will remain effective for

managing loss of material for SWS components. During the fall of 2005, NRC conducted an

integrated inspection which included an assessment of maintenance effectiveness for the ESW

system. Results confirmed that plant personnel had maintained the ESW system, assuring its

capability of performing its intended function. Deficiencies are detected and appropriate

corrective actions implemented.

During the audit and review, the staff asked the applicant for additional information related to

the erosion and corrosion identified during the 2000-2004 period, which resulted in component

replacements.

In its response, the applicant stated that the results of SWS visual and other non-destructive

examinations revealed erosion and areas of corrosion on internal and external surfaces.

Corrective actions included replacement of all four original RHRSW pumps, replacement of all

four EDG jacket water heat exhangers, and close monitoring of RHRSW and ESW pump

discharge strainer housings by ultrasonic inspections with repair, as necessary. Sections of the

ESW and normal service water (NSW) piping are scheduled for followup non-destructive

examinations to allow for sufficient replacement as required, prior to reaching degradation

limits. A number of ESW unit cooler/heat exchanger coils have been replaced and the

additional unit cooler/heat exchanger coils are scheduled for replacement as part of the

JAFNPP long term plan EN-PL-1 70..

The applicant also stated that approximately 1 percent of the ESW and NSW piping has been

replaced due to visual and non-destructive examinations. The piping was replaced with carbon

steel for the most part. Carbon steel piping has aged well at JAFNPP as evidenced by the more

than 30 years of service prior to the implementation of the extensive visual and non-destructive

examination controls now in place. Continuous chlorination is now performed for both the ESW

and NSW systems. The use of BULAB chemicals assists the chlorine in penetrating any buildup

within the piping and keeps dissolved substances and silt in suspension so as to exit the system

piping. The frequency of preventive maintenance (PM) activities is selected to minimize pipe

wall thinning and maximize design functionality. Periodic flow surveillance testing and flushing

of stagnant system legs are performed to control system degradation. Stainless steel has been

used in areas subject to erosion to extend the service life of piping exposed to cavitation.

The applicant stated that UT inspections of the RHRSW pump discharge and RHRSW system

strainers have been ongoing since 2001. Several below-minimum wall thickness areas of the

strainers have been repaired. No repairs have been necessary for the RHRSW pumps. The

ESW duplex strainers have experienced only a single repair due to wall thinning on the strainer

basket housings.

The staff determined that this operating experience demonstrates that the applicant's service

water integrity program is able to detect degradation of components prior to a loss of intended

function. Also, appropriate corrective actions are taken to prevent a recurrence of the

degradation or future component failures.

The staff interviewed applicant personnel and also reviewed operating experience reports and

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confirmed that the plant-specific operating experience did not include any aging effects for

systems and components within the scope of this program that are not bounded by industry

operating experience. The JAFNPP operating experience included detection of erosion,

corrosion, and blockage in system components via inspections and performance testing of

SWS components. These aging effects are consistent with industry operating experience, and

this AMP includes aging management activities, such as chemical treatment, performance

testing, visual inspections, non-destructive examination (NDE), and flushing activities, that are

appropriate to detect and manage this aging degradation. Corrective actions were taken in

accordance with the plant corrective action program prior to a loss of intended function of the

component. As an example of the applicant's implementation of the service water integrity

program and associated corrective actions, the staff reviewed a work order package for the

EDG 'D' jacket water cooler cleaning, visual inspection, and eddy current inspection. The work

order documented performance of the PM activity during which a small packing flange leak was

detected and repaired prior to returning the jacket water cooler to service. The staff finds that

this is a verification that the corrective action process is being implemented adequately.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1, item A.2.1.28, the applicant provided the UFSAR

supplement for the Service Water Integrity Program. The staff determines that the information

in the UFSAR supplement provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Service Water Integrity

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and the

associated justifications, and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed, so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.18 Structures Monitoring Program

Summary of Technical Information in the Application. LRA Section B. 1.27.2 describes the

existing Structures Monitoring Program as consistent, with enhancements, with GALL

AMP XI.S6, "Structures Monitoring Program."

Structures monitoring in accordance with 10 CFR 50.65 is addressed in Regulatory

Guide 1.160 and NUMARC 93-01. These two documents guide development of

licensee-specific programs to monitor the condition of structures and structural components

within the scope of 10 CFR 50.65 so there is no loss of structure or structural component

intended function. The program does not address protective coating monitoring and

maintenance because protective coatings are not relied upon to manage the aging effects for

structures included in the Structures Monitoring Program.

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Staff Evaluation. During its audit and review, the staff reviewed the enhancements to determine

whether the AMP, with the enhancements, remains adequate to manage the aging effects for

which it is credited.

The staff interviewed the applicant's technical staff and reviewed the Structures Monitoring

Program bases documents. Specifically, the staff reviewed the program elements and

associated bases documents to determine consistency with GALL AMP XI.S6.

The staff finds the applicant's Structures Monitoring Program acceptable because it conforms to

the recommended GALL AMP XI.S6, "Structures Monitoring Program," with enhancements as

described below.

Enhancement 1. The LRA states an enhancement to meet the following GALL Report program

element:

Element: 1: scope of program

Enhancement: The Structures Monitoring Program procedure will be

enhanced to specify that the manholes, duct banks,

underground fuel oil tank foundations, manway seals and

gaskets, hatch seals and gaskets, underwater concrete in

the intake structure, and crane rails and girders are

included in the program.

The staff reviewed the applicant's response and determined that the structures, structural

components, and their Aging Effect Requiring Managements (AERMs) under the scope of the

Structures Monitoring Program are included in LRA Tables 3.5.2-1 through 3.5.2-6. Visual

inspections of most plant structures are performed at five-year intervals. The intake and

discharge tunnel structures areas are performed at 10-year intervals. Visual inspections of

buried plant structures are performed when opportunistic excavation occurs. However, more

frequent inspections may be performed based on past inspection results, industry experience,

or exposure to a significant event (e.g., tornado, earthquake, fire, or chemical spill). The staff

found this information acceptable, since the corrective action program will address expansion of

scope when significant degradation is observed.

The staff finds this enhancement acceptable because when enhancements are implemented,

the Structures Monitoring - Structures Monitoring Program will be consistent with GALL

AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately

managed (Commitment No. 16 (JAFP-06-0109, dated July 31, 2007)).

Enhancement 2. The LRA states an enhancement to meet the following GALL Report program

element:

Element: 4: detection of aging effects

Enhancement: A- Guidance for performing structural examinations of

elastomers and rubber components (seals, gaskets,

seismic joint filler, drywell floor line seal and roof

elastomers) to identify cracking and change in material

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properties will be added to the Structures Monitoring

Program procedure.

B- Guidance for performing periodic inspections to confirm

the absence of aging effects for Lubrite surfaces in the

drywell radial beam seats will be added to the Structures

Monitoring Program procedure.

The GALL Report identified the following recommendation for the "detection of aging effects"

program element associated with the enhancement:

For each structure/aging effect combination, theinspection methods, inspection schedule, and

inspector qualifications are selected to ensure that aging degradation will be detected and

quantified before there is loss of intended functions. Inspection methods, inspection schedule,

and inspector qualifications are to be commensurate with industry codes, standards and

guidelines, and are to also consider industry and plant-specific operating experience. Although

not required, American Concrete Institute (ACl) 349.3R-96 and ANSI/ASCE 11-90 provide an

acceptable basis for addressing detection of aging effects. The plant structure monitoring

program is to contain sufficient detail on detection to conclude that this program attribute is

satisfied.

The applicant stated in the LRA for JAFNPP that cracks, gaps, and corrosion will be monitored

as stated in the program basis document. For concrete, the Structures Monitoring Program

manages loss of material, cracking, and change in material properties, as identified in LRA

Tables 3.5.2-1 through 3.5.2-6. The acceptance criteria are the absence of the following:

cracks, excessive rust bleeding, staining or discoloration, abrasion, erosion, cavitation, spalling,

scaling, leaching, excessive settlement, corrosion of reinforcing, and degraded waterproof

membranes. For steel, the Structures Monitoring Program manages the loss of material, as

identified in LRA Tables 3.5.2-1 through 3.5.2-6. The acceptance criteria are the absence of the

following: pitting, beam/column deflection, cracks, flaking coatings, excessive rust,

loose/missing bolts, peeling paint, and wide spread corrosion. For elastomers, the aging effects

managed are cracking and change in material properties. The acceptance criteria include the

absence of cracks and gaps.

During the audit and review, the staff asked the applicant whether it intends to inspect

inaccessible areas that may be exposed by excavation for any reason, whether the environment

is aggressive or not, and also whether it intends to inspect inaccessible areas if degradation is

observed in accessible areas which are exposed to the same environment. In its response, the

applicant stated that JAFNPP site procedure will be enhanced to require opportunistic

inspections of inaccessible concrete areas when they become accessible. This enhancement is

identified as Commitment No. 16 in a letter dated February 1, 2007. See staffs additional

evaluation in SER Section 3.5.2.2.1.

The staff also asked the applicant, during the audit and review, about the aging management of

inaccessible concrete areas and the groundwater for aggressive or non-aggressive. In its

response, the applicant stated that JAFNPP has determined that ground water is not

aggressive and will enhance to the structures Monitoring Program to perform an engineering

evaluation on a periodic basis at least once every five years of ground water samples to assess

aggressiveness (pH < 5.5, Chloride > 500 ppm and Sulfate > 1500 ppm).This enhancement is

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also identified as Commitment No. 16 in its letter dated February 1, 2007. The staff finds this

acceptable since opportunistic inspections will be performed to monitor the aggressiveness of

the concrete.

The applicant also stated that expanding inspection to other areas where significant concrete

degradation is observed in the accessible areas will continue to be part of its corrective action

program as identified in LRA Appendix B.0.3. The staff found this response to be acceptable

since the corrective action program will address expansion of scope when significant

degradation is observed.

The staff finds these enhancements acceptable because when enhancements are

implemented, the Structures Monitoring - Structures Monitoring Program will be consistent with

GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately

managed (Commitment No. 16).

Operatinq Experience. LRA Section B.1.27.2 states that inspections from 2000 through 2004 of

structural steel, concrete exposed to fluid, and structural elastomers revealed such degradation

as cracks, gaps, corrosion (rust), and flaking coatings. In 2002, due to documentation

deficiencies, inspections were not at specified frequencies. Structural monitoring inspections

were added to the PM work management system to meet future due dates. Structural

monitoring of concrete SCs during 2005 detected minor cracks that did not affect component

structural integrity. Monitoring of structural steel members detected minor corrosion only.

Inspection intervals were adjusted as necessary for future inspections to detect degradation

prior to loss of intended function. Detection of degradation and corrective action prior to loss of

intended function prove that the program is effective for managing aging effects for structural

components. A QA surveillance in August 2003 revealed no issues or findings with impact on

program effectiveness.

The staff interviewed the applicant's personnel and reviewed operating experience reports and

confirmed that the plant-specific operating experience did not include any aging effects for

components within the scope of this program that are not bounded by industry operating

experience. A review of the condition reports showed that potential degraded conditions are

identified and corrected through the applicant's corrective action process.

During the audit and review, the staff pointed out to the applicant that some BWR units have a

history of problems with containment penetration bellows and asked whether they have

evaluated this operating experience. In its response, the applicant stated that there are no

JAFNPP plant operating experiences similar to that identified at those facilities. The normal

environment for the JAFNPP drywell is dry and there has been no indication of contamination of

the bellows during construction at JAFNPP. In addition, containment bellows for JAFNPP are

not exposed to a corrosive environment. As such, stress corrosion cracking (SCC) is not

applicable to JAFNPP stainless steel bellows. The staff reviewed the applicant's response and

its evaluations and finds the applicant's response acceptable, since the environment conducive

to SCC does not exist at JAFNPP.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

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UFSAR Supplement. In LRA Section A.2.1.30, the applicant provided the UFSAR supplement

for the Structures Monitoring Program. The staff reviewed the applicant's license renewal

commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and

confirmed that the program enhancements are identified as Commitment No. 16, to be

implemented before the period of extended operation.

The staff determines that the information in the UFSAR supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring

Program, the staff finds those program elements, for which the applicant claimed consistency

with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed

that the implementation of the enhancements prior to the period of extended operation would

result in the existing AMP being consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.19 Water Chemistry Control - Closed Cooling Water Program

Summary of Technical Information in the Application. LRA Section B.1.29.3 describes the

existing Water Chemistry Control - Closed Cooling Water Program as consistent, with

exception, with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."

This program's preventive measures manage loss of material, cracking, and fouling for

components in closed cooling water systems (jacket cooling water subsystem for the

emergency diesel generator, RBCLC, and turbine building closed loop cooling (TBCLC)). These

activities monitor and control closed cooling water chemistry by plant-specific procedures and

processes based on EPRI guidance for closed cooling water chemistry.

Staff Evaluation. During its audit and review, the staff reviewed the exception to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The staff interviewed the applicant's technical staff and reviewed the Water Chemistry

Control-Closed Cooling Water Program bases documents. Specifically, the staff reviewed the

program elements and associated bases documents to determine consistency with GALL

AMP XI.M21.

In its response to the staff's inquiry, during the audit and review, regarding the EPRI guidance

document cited in LRA Section B.1.29.3 and the basis document as the basis for the activities

for monitoring and controlling closed cooling water chemistry, the applicant stated that the

program is based on EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline,

Revision 1 to TR-107396," published in April 2004. ALL AMP XI.M21, "Closed Cycle Cooling

Water System," cites EPRI TR-107396, "Closed Cooling Water Chemistry Guideline, "

published in October 1997, as the technical basis for the program. Revision 1 of the EPRI

guideline document includes more detail on the various water treatment methods used at

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nuclear power plants and provides more detailed information on control and diagnostic

parameters, monitoring frequencies, operating ranges, and action levels. At the staff's request,

the applicant provided documentation of its review and evaluation of EPRI TR-1007820 in

comparison to the original EPRI guideline and the recommended actions to incorporate the

Revision 1 guidelines into the JAFNPP program and procedures.

The staff reviewed the applicant's evaluation and confirmed that the applicant had incorporated

EPRI TR-1 007820 as the technical basis guideline for the Water Chemistry Control - Closed

Cooling Water Program. The staff determined that the use of EPRI TR-1007820 provides

guidance consistent with the recommendations in GALL AMP XI.M21 and offers more detail on

the various water treatment methods used at nuclear power plants, as well as control and

diagnostic parameters, monitoring frequencies, operating ranges, and action levels. Therefore,

the staff finds the use of EPRI TR-1007820 as the basis for this program acceptable.,

The staff finds the applicant's Water Chemistry Control - Closed Cooling Water Program

acceptable because it is consistent with the recommended GALL AMP XI.M21, "Closed-Cycle

Cooling Water System," with an exception as described:

Exception. The LRA Section B.1.21 states an exception to the GALL Report program elements

"parameters monitored or inspected," and "detection of aging effects."

Specifically, the exception states:

The JAFNPP Water Chemistry Control - Closed Cooling Water Program does

not include performance and functional testing.

The LRA Section B.1.29.3 discussion of this exception includes a footnote that states the

following:

While NUREG-1801, Section XI.M21, Closed-Cycle Cooling Water System

endorses EPRI report TR-1 07396 for performance and functional testing

guidance, EPRI report TR-107396 does not recommend that equipment

performance and functional testing be part of a water chemistry control program.

This appears appropriate since monitoring pump performance parameters is of

little value in managing effects of aging on long-lived, passive CCW system

components. Rather, EPRI report TR-107396 states in section 5.7 (Section 8.4

in EPRI report 1007820) that performance monitoring is typically part of an

engineering program, which would not be part of water chemistry. In most cases,

functional and performance testing verifies that component active functions can

be accomplished and as such would be included as part of Maintenance Rule

(10 CFR 50.65). Passive intended functions of pumps, heat exchangers and

other components will be adequately managed by the Closed Cooling Water

Chemistry and One-Time Inspection programs through monitoring and control of

water chemistry parameters and verification of the absence of aging effects.

During the audit and review, the staff asked the applicant for additional information to justify not

performing testing and functional inspections as part of this AMP.

In response, the applicant stated that in most cases, functional and performance testing verifies

that component active functions can be accomplished and, as such, are governed by the

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Maintenance Rule (10 CFR 50.65). For example, loss of material cannot be detected by system

performance testing. Passive intended functions of pumps, heat exchangers, and other

components will be adequately managed by the Closed Cooling Water Chemistry and

One-Time Inspection programs through monitoring and control of water chemistry parameters

and verification of the absence of aging effects.

In addition, the applicant stated that corrosion coupons are used to monitor the effects of

corrosion on the reactor building closed loop cooling water and the turbine closed loop cooling

water systems. The applicant also stated that LRA Section B.1.21, "One-Time Inspectioh,"

describes inspections planned to verify the effectiveness of the water chemistry control

programs to ensure that significant degradation is not occurring and component intended

function is maintained during the period of extended operation.

The staff reviewed EPRI Report TR-1 007820 (Revision 1 to EPRI TR-107396) and determined

that it does not recommend that performance and functional testing be part of the water

chemistry control program. This engineering testing could be performed as part of another

program. Usually, the Maintenance Rule (10 CFR 50.65) dictates the requirements of the

performance and functional testing. The staff also noted that corrosion coupons are used to

monitor the effects of corrosion on the reactor building closed loop cooling water and the

turbine closed loop cooling water systems. This will provide an effective means of detecting

corrosion and will provide additional assurance that aging effects are being managed. Finally,

the staff noted that a one-time inspection will be performed to verify the effectiveness of this

program for managing aging in the closed loop cooling water systems within the scope of this

program. The staff finds that the activities included in this program are adequate to manage the

aging effects for which the program is credited without the need for performance and functional

testing. On this basis, the staff finds this exception acceptable.

Operatinq Experience. The program basis document states that from 2000 through 2004 there

were several CRs of adverse trends in parameters monitored by the Water Chemistry Control - Closed Cooling Water Program. Corrective actions were taken within the Corrective Action

Program to preclude violations of acceptance criteria. From 2000 through 2004, there were a

few incidents of parameters monitored by the Water Chemistry Control - Closed Cooling Water

Program outside of acceptance criteria. Monitoring frequency was increased and the

parameters returned to within the prescribed normal operating range as soon as possible. The

dissolved oxygen in the RBCLC system was a-long term plant concern. Loss of material

occurred in the RBCLC piping due to low levels of dissolved oxygen in the water. In

August 2003, an oxygen injection system was added to control dissolved oxygen between

30-200 ppb. A corrosion study in 2004 showed that this control of dissolved oxygen had

lowered the general corrosion rate for carbon steel in RBCLC water.

The TBCLC system has had high dissolved oxygen concentration, which can cause pitting

corrosion in carbon steel. An oxygen removal skid was installed and leaks were repaired to

lower the dissolved oxygen concentration. Periodic feed and bleed operations to reduce tritium

in the TBCLC system increase the concentration, requiring use of the oxygen removal skid. A

corrosion study in 2004 revealed slightly higher general corrosion rates for TBCLC carbon steel

than seen in the past. Corrective actions have been implemented to control TBCLC dissolved

oxygen between 30 and 200 ppb. The Cycle 16 average chemistry data for the RBCLC and

TBCLC systems compare favorably with the action Level 1 parameter values from the BWR

Water Chemistry Guidelines. The dissolved oxygen in the RBCLC and TBCLC systems was

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better controlled this cycle with the oxygen removal skid for the TBCLC and a new oxygen

addition system for the RBCLC system. Continuous confirmation of water quality and timely

corrective action prove that the program is effective in managing component loss of material. A

QA surveillance in 2004 revealed no issues or findings with.impact on program effectiveness.

The staff reviewed a corrosion study conducted by the applicant to determine TBCLC general

corrosion rates by measurements and calculations based on the condition of corrosion coupons

and by projecting the life of future system components. The results showed that the general

corrosion rates in the TBCLC system are low, with the highest rate being exhibited by carbon

steel. Extent of wall thinning falls into the 'Evaluate' category of plant procedure ENN-DC-1 33.

The corrosion rate of the carbon steel was found to be 'Fair' and all other materials 'Excellent'

according to EPRI guidelines. The corrosion rate calculation shows that the AMP has

adequately controlled corrosion or SCC.

The staff reviewed two condition reports from the applicant's operating experience program

response to increased dissolved oxygen in the TBCLC system. In one CR, dissolved oxygen

was found to be increasing at a high rate and, in response, the system deoxygenation skid was

put into service more frequently. In the other CR, TBCLC dissolved oxygen was found to be

increasing beyond the 3000 ppb action level and the deoxygenation skid was put into service to

return the dissolved oxygen level to within limits. The staff finds that these examples are

indications that system problems are being detected by the program and appropriate corrective

actions are being implemented.

The staff reviewed two examples of response to RBCLC water chemistry operating experience.

In the first example, responding to increases in RBCLC chloride, sulfate, and nitrate, the

applicant initiated an action plan to identify the source of raw water in-leakage and then added

a side stream demineralizer to return the RBCLC water quality to within limits. In the second

example, the RBCLC experienced abnormal chemistry problems for an extended period. A

review was conducted by the applicant to determine whether the chemistry problems had a

potential aggregate effect in accordance with Institute of Nuclear Power Operations (INPO)

SOER 02-4, "Reactor Pressure Vessel Head Degradation at Davis-Besse Nuclear Power

Station," requirements. The review determined that there was no aggregate effect and that

each of the abnormal chemistry conditions was either corrected or was being addressed by

corrective actions. The staff finds that these examples are indications that system problems are

being detected by the program and appropriate corrective actions are being implemented.

The staff also reviewed the operating experience provided in the applicant's operating

experience reports and determined that there were no aging effects identified that are outside

the bounds of industry operating experience. The aging effects identified at JAFNPP for

auxiliary system components exposed to treated water are loss of material, corrosion, and

cracking, which are all consistent with industry operating experience. The components within

the scope of this program are constructed of carbon steel, stainless steel, gray cast iron, and

copper alloy. Exposure of these materials to an environment of treated water could result in the

aging effects of loss of material, corrosion, or cracking. These aging effects are directly related

to water chemistry and the dissolved oxygen concentration in the water. The JAFNPP indicates

that instances of low and high oxygen concentration have been experienced in the RBCLC

system and TBCLC systems, respectively. These instances were detected by this program and

appropriate corrective actions were taken to restore oxygen concentrations to acceptable levels

prior to a loss of intended function of the component. An oxygen injection system was installed

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in the RBCLC system to increase oxygen concentrations. An oxygen removal skid was installed

in the TBCLC systems and leaks were repaired to reduce the oxygen concentration in those

systems. This operating experience provides objective evidence to demonstrate that this

program is effective in detecting conditions that would make the components within.the scope

of this program susceptible to aging degradation, and that appropriate corrective actions are

taken in a timely manner.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.34, the applicant provided the UFSAR supplement

for the Water Chemistry Control - Closed Cooling Water Program. The staff determines that the

information in the UFSAR supplement provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control -

Closed Cooling Water Program, the staff finds those program elements, for which the applicant

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the

exception and the associated justifications, and determined that the AMP, with the exception, is

adequate to manage the aging effects for which it is credited. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 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).

3.0.3.2.20 Bolting Integrity Program

Summary of Technical Information in the Application. LRA Section 6.1.30 describes the new

Bolting Integrity Program as consistent, with enhancements, with GALL AMP XI.M18, "Bolting

Integrity."

The Bolting Integrity Program (BIP) relies on recommendations for a comprehensive bolting

integrity program, as delineated in NUREG-1 339, and industry recommendations, as delineated

in EPRI NP-5769, with the exceptions noted in NUREG-1 339 for safety-related bolting. The

program relies on industry recommendations for comprehensive bolting maintenance as in

EPRI TR-1 04213 for pressure-retaining bolting and structural bolting.

Staff Evaluation. During its audit and review, the staff reviewed the enhancements to determine

whether the AMP, with the enhancements, remains adequate to manage the aging effects for

which it is credited.

The staff interviewed the applicant's technical staff and reviewed the Bolting Integrity Program

bases documents. Specifically, the staff reviewed the program elements and associated bases

documents to determine consistency with GALL AMP XI.M18.

During the audit and review, the staff verified that the applicant's program attributes for the BIP

were all consistent with the program attributes in the GALL AMP, except for the "preventive

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actions" program attribute. The staff also verified that the applicant's program includes all

ASME Code, Section Xl inspection requirements for ASME Code Class 1, 2, and 3 bolted

connections by invoking the inspections for these bolts that are implemented as part of the

applicant's ISI Program.

The staff noted that the applicant entered the 4h Ten-Year ISI Interval for JAFNPP in

January 2007. The applicant was required by 10 CFR 50.55a (g)(4)(I) to update the ASME

Code, Section XI (Section XI code of record) to the 2001 Edition of Section XI, inclusive of the

2003 Addenda. The staff requested confirmation from the applicant that the Section XI code of

record for the 4 th Ten-Year ISI Interval is the 2001 Edition of Section XI, inclusive of the 2003

Addenda.

The applicant clarified in its response that the 2001 Edition of Section XI, inclusive of the 2003

Addenda will be the new Section Xl code of record for those JAFNPP AMPs referencing or

crediting Section XI requirements. The applicant also stated that LRA Section A.2.1.18 will be

amended to delete the relevant information for the 3 rd 10-Year ISI Interval and to incorporate

the relevant information for the 4th 10-year ISI Interval for JAFNPP, including a statement that

the 2001 Edition of Section XI, inclusive of the 2003 Addenda is the applicable edition of

Section XI for the 4h 10-Year ISI Interval. The applicant amended the LRA (Amendment 5) in its

letter dated February 1, 2007.

The 4th 10-Year ISI Interval for JAFNPP will be the 10-Year interval in effect if the LRA is

approved by the staff. The applicant's amendment of the LRA is in compliance with the

requirements of 10 CFR 50.55a because the applicant was required by paragraph (b) of the

rule to update in Section XI edition of reference to 2001 Edition of Section Xl (inclusive of the

2003 Addenda), one year prior to entering the 4t 10-Year ISI Interval for JAFNPP. Based on

this assessment, the staff concludes that the changes to the LRA are acceptable because they

are in compliance with the requirements of 10 CFR 50.55a and in conformance (i.e., consistent)

with the "scope of program" element in GALL AMP XI.M1, "ASME Section XI Inservice

Inspection, Subsections IWB, IWC, and IWD."

The staff noted that the BIP also includes inspections for Non-Code Class mechanical and

structural bolted connections. The staff verified that the inspections credited in this AMP for

these components are consistent with the inspection criteria for Non-Code Class mechanical

and structural bolted connections in GALL AMP XI.M18.

The staff finds the applicant's Bolting Integrity Program acceptable because it is consistent with

the recommended GALL AMP XI.M18, "Bolting Integrity," with an enhancement as described:

Enhancements. The LRA states an enhancement to the GALL Report program element

"preventive actions." Specifically, the enhancement states:

The actual yield strength is used in selecting materials of low-susceptibility to

stress corrosion cracking (SCC) and to preclude the use of lubricants containing

MoS 2 for bolting at JAFNPP.

The applicant is using SA 193, Grade B7 steel bolts in the JAFNPP design, although the design

does include some stainless steel bolts in stainless steel bolted connections. These SA 193,

Grade B7 steel bolts are made from chromium-molybdenum alloy steel materials that are

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quenched and tempered for additional hardness. Industry experience has demonstrated that SA

193 B7 bolting materials may be more susceptible to SCC when the yield strength of the

procured materials is in excess of 150 ksi or if the hardness of the procured material is in

excess of 32 on a Rockwell C Hardness scale. The staff has established its position that the

actual yield strength of SA 193, Grad B7 bolts be limited to less than 150 ksi to mitigate the

probability that SCC will occur in the bolting materials. The applicant has committed to monitor

the actual yield strength property of procured SA 193, B7 bolting to ensure that the bolting used

in the facility is in conformance with the staff's position on yield strength properties for the

procured bolting materials.

The Journal Article "Effect of Molybdenum Disulfide on Electrochemical Corrosion of Metals,"

Journal of Chemistry and Technology of Fuels and Oils, Volume 5, Number 8 (August 1969),

indicates that use of MoS 2 in lubricants or greases may increase the potential for corrosion to

occur at friction points of mechanically secured metal components (such as bolted connections)

and should be avoided. The applicant has committed to the practice of precluding the use of

MoS 2-containing lubricants. This is in conformance with the recommendations of this journal

article and is acceptable.

The staff finds this enhancement acceptable because when implemented the Bolting Integrity

Program "preventive actions" program attribute will be consistent with GALL AMP XI.M18 and

will add assurance of adequate management of aging effects (Commitment No. 19

(JAFP-06-0109, dated July 31, 2007)).

Operatingq Experience. LRA Section B.1.30 states that industry operating experience forming

the basis for the Bolting Integrity program is described in the operating experience element of

the GALL Report program description. Plant-specific operating experience is consistent with the

operating experience in the GALL Report program description and provides reasonable

assurance that the Bolting Integrity Program will manage aging effects so that components will

continue to perform their intended functions consistently with the CLB for the period of

extended operation.

The staff noted that applicant's reviews of operating experience and condition reports did not

identify cracking or loss of preload as aging effects requiring management for pressure

boundary bolting. The plant procedures implement the recommendations of NUREG-1 339,

"Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power

Plants," for pressure boundary bolting within the scope of license renewal. Plant procedures

address material and lubricant selection, design standards, and good bolting maintenance

practices in accordance with EPRI 5067, "Good Bolting Practices."

The staff also interviewed the applicant's technical staff and reviewed operating experience

reports including applicable condition reports and confirmed that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.2.1.35, the applicant provided the UFSAR supplement

summary description for the BIP. The staff reviewed LRA Section A.2.1.35 and compared it to

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the corresponding UFSAR supplement description for BIPs in SRP-LR Table 3.1-2. The staff

determined that the UFSAR supplement summary description for the applicant's BIP is

consistent with the corresponding summary description in SRP-LR Table 3.1-2. The staff

reviewed the. applicant's license renewal commitment list in LRA Amendment 5, Attachment 1,

Revision 1, dated February 1, 2007, and confirmed that the program enhancement is identified

as Commitment No. 19, to be implemented before the period of extended operation.

Based on this assessment, the staff concludes that LRA Section A.2.1.35 provides an adequate

UFSAR supplement summary description of the BIP, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's BIP, the staff finds those

program elements, for which the applicant claimed consistency with the GALL Report are

consistent. Also, the staff reviewed the enhancements and confirmed that the implementation of

the enhancements prior to the period of extended operation would result in the existing AMP

being consistent with the GALL AMP to which itwas compared. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d).

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

In LRA Appendix B, the applicant identified that the following AMPs are plant-specific:

* Heat Exchanger Monitoring Program

* Containment Inservice Inspection Program

* Inservice Inspection Program

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control - Auxiliary Systems Program

* Bolted Connections Program

For AMPs not consistent with, or not addressed in the GALL Report, the staff performed a

complete review to determine whether these AMPs are adequate to monitor or manage aging.

The staff's review of these plant-specific AMPs is documented in the following sections of this

SER.

3.0.3.3.1 Heat Exchanger Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.15 describes the new

plant-specific Heat Exchanger Monitoring Program.

The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation and, if

found, evaluate its effects on the heat exchanger's design functions including its ability to

withstand a seismic event. Representative tubes of heat exchangers will be eddy current-tested

at a frequency determined by internal and external operating experience to detect aging effects

prior to loss of intended function. Along with each eddy current test, there will be visual

inspections on accessible heat exchanger heads, covers, and tube sheets to monitor surface

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conditions for loss of material. The heat exchangers include the HPCI turbine lube oil coolers,

gland seal condensers, and EDG lube oil heat exchangers. The program will be implemented

fully prior to the period of extended operation. This is Commitment No. 7 (JAFP-06-0109, dated

July 31, 2007) in the applicant's letter dated December 6, 2006.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.1.15 regarding the applicant's demonstration of the Heat Exchanger

Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation.

The staff interviewed the applicant's technical staff and reviewed program basis document

which provides an assessment for each of the AMP elements.

During the audit and review, the staff reviewed the Heat Exchanger Monitoring Program against

the AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, focusing its

review on how the program manages aging effects through the effective incorporation of

10 elements (i.e., "scope of program;" "preventive actions," "parameters monitored or

inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating

experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are part of the site-controlled QA program. The staff's evaluation of

the QA program is discussed in SER Section 3.0.4. The remaining seven elements are

discussed below.

(1) Scope of Program - In LRA Section B.1.15 the applicant stated that the Heat Exchanger

Monitoring Program will manage aging effects on selected heat exchangers in various

systems as identified in aging management reviews (AMRs).

The staff reviewed the applicant's program basis document for this AMP, and

determined that the scope of this AMP includes the HPCI turbine lube oil coolers and

gland seal condensers, and the EDG lube oil heat exchangers. The staff determined

that these components are not covered by other AMPs; therefore, they are appropriately

included within the scope of this program. The staff finds the "scope of program"

acceptable since it specifically identifies the components within the scope of this

program.

The staff confirmed that the specific components for which the program manages aging

effects are identified by the applicant, which satisfies the criterion as defined in SRP-LR

Appendix A.1.2.3.1. The staff finds this program element acceptable.

(2) Preventive Actions - In LRA Section B.1.15, the applicant stated that this is an

inspection program and no actions are taken as part of this program to prevent

degradation.

The staff reviewed the applicant's program basis document for this AMP, and

determined that this is a condition monitoring program; therefore, it does not rely on

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preventive actions.

This is an inspection program and no actions are taken as part of this program to

prevent degradation. SRP Item 2, "preventive action," is not applicable .because the

Heat Exchanger Monitoring Program is an inspection program. The staff confirmed that

the "preventive actions" program element satisfies the criterion defined in SRP-LR

Section A.1.2.3.2. The staff concludes that this program element is acceptable.

(3) Parameters Monitored or Inspected - In LRA Section B.1.15, the applicant stated that

where practical, eddy current inspections of shell-and-tube heat exchanger tubes will be

performed to determine tube wall thickness. Visual inspections will be performed on

heat exchanger heads, covers and tube sheets where accessible to monitor surface

condition for indications of loss of material.

The staff determined that the parameter to be monitored is tube wall thickness, using

eddy current inspection. When this is not practical, indications of loss of material will be

monitored using visual inspection.

During the audit and review, the staff asked the applicant for further information on

when visual inspection will be used in lieu of eddy current testing.

In response, the applicant stated that eddy current testing Will be performed when

practical as determined by the tubes' physical location, physical size, orientation,

physical dimensions, accessibility and disassembly of the heat exchangers. If eddy

current inspection is determined to be impractical, aging of the heat exchanger tubes will

be managed using visual inspection of the external portion of heat exchanger tubes,

which is conducted during maintenance activities and is focused on detecting the extent

of tube erosion, corrosion, fouling and scaling, and on the detection of corrosion at the

tubesheet and rolled tube joints. In some cases, heat exchanger heads, partition plates,

baffles, covers, or tubesheets are of the same material/environment combination as

tubes, which provides additional data for determining inspection frequency and the

presence of aging effects.

The staff determined that the applicant's use of wall thickness via eddy current testing,

or indications of loss of material via visual inspection as the parameters to be monitored

will provide an effective method of detecting degradation of heat exchanger tubes. The

components within the scope of this program are the HPCI turbine lube oil coolers and

gland seal condensers, and the EDG lube oil heat exchangers. These heat exchangers

have tubes constructed of copper alloy that are exposed to lube oil or treated water on

the external surface. The aging effect of concern for these components is loss of

material due to wear. This aging effect can result in wall thinning of the heat exchanger

tubes, which is what the applicant is crediting this program to manage. Eddy current

testing has been shown to be an effective method of monitoring for tube wall defects

and degradation, and is a proven industry inspection practice. The results of the eddy

current inspection will provide timely detection of degradation so that corrective actions

can be taken prior to a loss of component intended function. Visual inspections of heat

exchanger components with the same material/ environment combination as the tubes

will also provide information that can be used to determine if degradation is occurring,

and whether further action is needed to manage aging. The visual inspections will

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provide timely detection of degradation so that corrective actions can be taken prior to a

loss of component intended function. On this basis, the staff finds the parameters

monitored acceptable to manage aging for the heat exchangers within the scope of this

program.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concludes that this

program element is acceptable.

(4) Detection of Aging Effects - In LRA Section B. 1.15, the applicant stated that loss of

material is the aging effect managed by this program. Representative tubes within the

sample population of heat exchangers will be eddy current tested at a frequency

determined by internal and external operating experience to ensure that effects of aging

are identified prior to loss of intended function. Visual inspections of accessible heat

exchangers will be performed on the same frequency as eddy current inspections.

In LRA Section B. 1.15, the applicant further stated that an appropriate sample

population of heat exchangers will be determined based on operating experience prior to

inspections. Inspection can reveal loss of material that could result in degradation of the

heat exchangers. Fouling is not addressed by this program.

During the audit and review, the staff asked the applicant to provide additional

information on the rationale for establishing the sample population for eddy current

inspection.

In response, the applicant stated that the sample population of heat exchangers will be

determined based on the materials used in construction of the heat exchanger tubes

and the associated environments, as well as the type of heat exchanger (for example,

shell and tube type). At least one heat exchanger of each type, material, and

environment combination will be included in the sample population. This ensures that

potential impacts of different design, material and environment combinations will be

addressed. Representative tubes within the heat exchanger sample population will be

selected based on previous eddy current inspections, work order history, such as

corrective maintenance, tube plugging history, engineering evaluation, EPRI guidance,

and service conditions of the heat exchanger. The sample tubes are selected based

upon the locations in the bundle most prone to discovering mechanistic failures, such as

pitting, tube erosion, and lagging vibration wear/fret damage.

The staff determined that the applicant's approach to determining a sample population

for eddy current testing will be based on the materials of construction and the

environment to which the heat exchanger tubes are exposed. In addition, the type of

heat exchanger (for example, shell and tube type) will be considered. The applicant will

include at least one heat exchanger of each type, material, and environment

combination in the sample population to ensure that the potential impacts of different

design, material and environment combinations will be addressed. The staff determined

that this approach will provide reasonable assurance that the effects of aging for which

this program is credited will be effectively detected since each material/environment

combination will be inspected. In addition, tubes located in areas that are most

susceptible to degradation will be included in the sample population, which provides

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assurance that the leading indicators of degradation will be inspected. Therefore, the

staff finds this approach for determining sample population acceptable.

During the audit and review, the staff asked the applicant to provide additional

information on the inspection frequency to be used for eddy current testing and visual

inspection.

In response, the applicant stated that baseline eddy current testing will be performed to

document the as-found condition of the components. The results of these baseline

inspections will then be used to determine the frequency of future inspections and the

sample size to be inspected. A similar approach will be used for visual inspections, in

which baseline results will be used to determine the frequency of future inspections.

The staff determined that the applicant's approach of using baseline results to document

the as-found condition of the components, and then determining future test or inspection

frequencies based upon the baseline results is reasonable. The baseline results will

reflect plant-specific operating experience with these components, and will provide

objective evidence of the condition of the components that can be used to develop

future test or inspection frequencies. Depending upon the extent of the degradation

detected during the baseline test or inspection, appropriate frequencies for future testing

or inspections can be determined. If there is significant degradation detected by the

baseline results, a more frequent test or inspection frequency would be warranted, and

can be implemented. Therefore, the staff finds the applicant's approach for determining

test and inspection frequency acceptable.

The staff determined that the applicant's- use of eddy current testing and visual

inspections will provide an effective method of detecting degradation of heat exchanger

tubes. The components within the scope of this program are the HPCI turbine lube oil

coolers and gland seal condensers, and the EDG lube oil heat exchangers. These heat

exchangers have tubes constructed of copper alloy that are exposed to lube oil or

treated water on the external surface. The aging effect of concern for these components

is loss of material due to wear. This aging effect can result in wall thinning of the heat

exchanger tubes, which is what the applicant is crediting this program to manage. Eddy

current testing has been shown to be an effective method of monitoring for tube wall

defects and degradation, and is a proven industry inspection practice. The results of the

eddy current inspection will provide timely detection of degradation so that corrective

actions can be taken prior to a loss of component intended function. Visual inspections

of heat exchanger components during maintenance, or for components with the same

material/environment combination as the tubes will also provide information that can be

used to determine if degradation is occurring and whether further action is needed to

manage aging. The visual inspections will provide timely detection of degradation so that

corrective actions can be taken prior to a loss of component intended function. On this

basis, the staff finds the activities for the detection of aging effects acceptable to

manage aging for the heat exchangers within the scope of this program.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.4. The staff concludes that this program

element is acceptable.

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(5) Monitoring and Trending - In LRA Section B.1.15, the applicant stated that results will be

evaluated against established acceptance criteria and an assessment will be made

regarding the applicable degradation mechanism, degradation rate and allowable

degradation -level. This information will be used to develop future inspection scope and

to modify inspection frequency, if appropriate. Wall thickness will be trended and

projected to the next inspection. Corrective actions will be taken if projections indicate

that the acceptance criteria may not be met at the next inspection.

The staff reviewed the applicant's program basis document for this AMP and verified

that monitoring and trending activities will include comparison of wall thickness test

results against established acceptance criteria. These results will be evaluated to

determine if corrective actions are required or if modifications are needed to the

inspection frequency. The wall thickness results will also be trended~against prior wall

thickness results and projected to the next inspection. This will provide predictability of

the extent of degradation, as well as a forward projection of the degradation. This

projection can be used to ensure that timely corrective actions can be taken, should the

rate of degradation be found unacceptable, prior to the loss of component intended

function. The staff determined that these activities are adequate to meet the monitoring

and trending program element for this AMP. On this basis, the staff finds this program

element acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.5. The staff concludes that this program

element is acceptable.

(6) Acceptance Criteria - In LRA Section B.1.15, the applicant stated that the minimum

acceptable tube wall thickness for each heat exchanger to be eddy current inspected will

be established based upon a component-specific engineering evaluation. Wall thickness

will be acceptable if greater than the minimum wall thickness for the component.

In LRA Section B.1.15, the applicant further stated that the acceptance criterion for

visual inspections of heat exchanger heads, covers and tubesheets will be the absence

of evidence of degradation that could lead to loss of function. If degradation that could

lead to loss of intended function is detected, a condition report will be written and the

issue resolved in accordance with the site corrective action program.

The staff determined that the acceptance criteria for ultrasonic inspections will be

established through a component-specific engineering evaluation. Each component will

be evaluated in terms of its design function and operating conditions to determine the

minimum acceptable tube wall thickness that will allow that component to meet its

intended function. The acceptance criteria will ensure that the heat exchanger tubes

have sufficient wall thickness to perform their intended function, consistent with the

current licensing basis during the period of extended operation. Eddy current testing will

be performed periodically to measure the tube wall thickness and compare it to the

acceptance criterion established by the engineering evaluation. If the tube wall thickness

is found to be below the minimum acceptable wall thickness, or if projections show that

the wall thickness will reach the minimum acceptable value prior to the next inspection,

corrective actions will be taken in accordance with the plant corrective action program.

In addition, the visual examination acceptance criteria will ensure that degradation that

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could lead to a loss of intended function is not occurring. If degradation is detected,

corrective actions in accordance with the requirements of Appendix B will be taken in

accordance with the plant corrective action program. On this basis, the staff finds this

program element acceptable.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6. The staff concludes that this program element is

acceptable.

(10) Operating Experience - LRA Section B.1.15 states that the Heat Exchanger Monitoring

Program is a new program. The elements which comprise this program (e.g., the scope

of the inspections and inspection techniques) are consistent with industry practice.

Operating experience provides reasonable assurance that implementation of the Heat

Exchanger Monitoring Program will manage aging effects so that components will

continue to perform their intended functions consistently with the CLB for the period of

extend operation.

During the audit and review, the staff asked the applicant for additional information on

the JAFNPP plant-specific operating experience related to the components for which

this AMP is credited to manage aging.

In response, the applicant stated that the Heat Exchanger Monitoring Program manages

loss of material for copper alloy heat exchanger tubes in the lube oil and gland seal

condenser subsystems of the HPCI pump turbine and EDG engine lube oil cooler. Of

these components only the HPCI turbine lube oil cooler has been inspected. These

inspections occurred in 1998 and 2006 and detected no evidence of degradation. A

review of site condition reports and records did not document any failures on these heat

exchangers.

The staff determined that the lack of degradation for the HPCI pump turbine lube oil

cooler provides an acceptable indication that no aging effects outside the scope of

industry operating experience are occurring. Since the EDG lube oil coolers have the

same material/environment combination as the HPCI pump turbine lube oil cooler, and

similar operating conditions, the EDG lube oil cooler is expected to have a similar lack of

degradation. Therefore, the staff finds that the plant-specific operating experience

confirms that the components within the scope of this program are not experiencing

aging effects not bounded by industry operating experience.

The staff also reviewed the condition report documenting the eddy current testing of

heat exchanger 93WE-1B in which tube wall thinning was found. The wall loss exceeded

the general acceptance criteria of 20% per plant procedure AP-1 9.14; therefore, an

evaluation was performed to compare the as-found wall thickness with the minimum

allowable wall thickness, as determined by calculation JAF-CALC-EDG-02946. The

evaluation found the tube to have a remaining service life of 2.2 years. Based on this

evaluation, corrective actions were implemented to increase the PM frequency for

cleaning and eddy current testing of the heat exchanger, and to obtain a second data

point. A work order was also issued to replace the heat exchanger as a contingency.

The staff determined that, while this heat exchanger is not within the scope of this

program, this event demonstrates that heat exchanger eddy current inspections are

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performed at JAFNPP and are effective at detecting degradation in a timely manner,

prior to a loss of component intended function. In addition, the corrective actions taken

are appropriate to ensure that the cause of the degradation is properly managed.

The staff interviewed the applicant's personnel and also reviewed plant operating

experience reports and noted that none of the condition reports identified as

aging-related involved the HPCI pump turbine or EDG engine oil coolers. The staff finds

this an acceptable indication that these heat exchanger components at JAFNPP are not

experiencing any aging effects not bounded by industry operating experience.

The staff recognizes that heat exchangers with tubes constructed of copper alloy and

exposed to lubricating oil or treated water can experience a loss of material due to wear.

While the plant-specific operating experience at JAFNPP does not include.evidence that

this is occurring for the heat exchangers within the scope of this program, this aging

effect is consistent with industry operating experience and should be managed. This

aging effect can result in thinning of the tube walls, which, if not corrected, could result

in a loss of component intended function. The applicant's heat exchanger monitoring

program includes periodic eddy current testing of heat exchanger tubes to monitor tube

wall thickness. The test results are compared to acceptance criteria, and are trended to

project tube wall thickness to the next inspection. The staff finds that these activities will

provide timely detection of loss of material in the heat exchanger tubes so that

corrective actions can be taken prior to a loss of component intended function.

The staff confirmed that the "operating experience" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element

acceptable.

UFSAR Supplement. In LRA Section A.2.1.16, the applicant provided the UFSAR supplement

for the Heat Exchanger Monitoring Program. The staff reviewed the applicant's license renewal

commitment list in LRA Amendment 5, Attachment 1, Revision 1, dated February 1, 2007, and

confirmed that the implementation of the Heat Exchanger Monitoring Program is identified as

Commitment No. 7, to be implemented before the period of extended operation. The staff

reviewed this section and determined that the information in the UFSAR supplement provides

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Heat Exchanger Monitoring

Program, the staff concludes that the applicant will have a program demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.3.2 Containment Inservice Inspection Program

Summary of Technical Information in the Application. LRA Section B. 1.16.1 describes the

existing, plant-specific Containment Inservice Inspection Program.

The program uses nondestructive examination techniques to detect and characterize flaws.

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Three different types of examinations are volumetric, surface, and visual. The volumetric are

the most extensive with radiographic, ultrasonic, or eddy current examinations to detect surface

and subsurface flaws. Surface examinations like magnetic particle or dye penetrant testing

detect surface flaws. There are three specified levels of visual examinations. The VT-1 visual

examination assesses the surface condition for cracks and symptoms of wear, corrosion,

erosion, or physical damage. VT-1 can be done with either direct visual observation or remote

examination by various optical/video devices. The VT-2 examination specifically locates

evidence of leakage from pressure-retaining components (period pressure tests). While the

system is under pressure for a leakage test, visual examinations detect direct or indirect

indications of leakage. The VT-3 examination determines the general mechanical and structural

condition of components and supports and detects discontinuities and imperfections. For

containment ISI, general visual and detailed visual in addition to VT examinations are used.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information:

included in LRA Section B.1.16.1 regarding the applicant's demonstration of the Containment

Inservice Inspection Program to ensure that the effects of aging, as discussed above, will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation.

The staff reviewed the Containment Inservice Inspection Program against the AMP elements

found in SRP-LR Section A. 1.2.3 and SRP-LR Table A. 1-1, focusing its review on how the

program manages aging effects through the effective incorporation of 10 elements (i.e., "scope

of program," "preventive actions," "parameters monitored or inspected," "detection of aging

effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation

process," "administrative controls," and "operating experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are parts of the site-controlled QA program. The staff's evaluation

of the QA program ("corrective actions," "confirmation process," and "administrative controls,"

program elements) is discussed in SER Section 3.0.4.

(1) Scope of Program - The applicant stated that in LRA Section B.1.16.1, for the "scope of

program" program element, that this program, under ASME Code Section Xl,

Subsection IWE, manages loss of material for the primary containment and its integral

attachments. The primary containment is a GE Mark I pressure suppression

containment system. The system consists of a drywell (housing the RV and reactor

coolant recirculation loops), a pressure suppression chamber (housing a water pool),

and the connecting vent system between the drywell and the water pool, isolation

valves, and containment cooling systems. The code of construction for the containment

structure is the ASME Code Section III, 1968 Edition, including the 1968 Summer

Addenda.

During the audit and review, the staff asked the applicant the following for this program:

(1) identify the supports that are currently in the program, (2) identify the supports that

will be added to the scope, (3) specify the current inspection program and describe the

current inspection details for the MC supports that are identified in (2) above, and( 4)

confirm that, all MC supports will be included within the scope of this inspection

program.

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In its response, the applicant stated: (1) Currently, JAFNPP has 16 torus saddle

supports, 4 torus earthquake ties and 8 upper drywell stabilizer supports, (2) All torus

supports, earthquake ties and upper drywell stabilizer supports are currently scheduled

for examination during the 4th ten-year inspection interval and will be in accordance with

ASME Section XI, 2001 Edition with 2003 Addenda. There are no other supports added,

(3) The current IWE program was developed in accordance with ASME Section Xl, 1998

Edition with 1998 Addenda, which required 100% to be inspected either prior to and/or

during RFO17 in 2008, (4) All torus supports, earthquake ties, and upper drywell

stabilizer supports continue to be examined during the period of extended operation.

The'staff reviewed the above applicant's response and Aging Management Review

Evaluation Report JAF-RPT-05-LRD02, Revision 4, and determined that the specific

components for which the program manages aging effects are identified by the

applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1.

The staff confirmed that the "scope of program program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.1. The staff concludes that this program element is

acceptable.

(2) Preventive Actions - In LRA Section B.1.16.1, the applicant stated that for the

"preventive actions" program element, this program is a monitoring program that does

not include preventive actions.

The staff found that the applicant's Containment Inservice Inspection Program is only an

inspection program and the inspections performed under this program will only monitor

the condition of the primary containment and its integral attachments and will not

perform any preventive or mitigating action for aging effects/mechanisms. On this basis,

the staff found the applicant's "preventive actions" program element is acceptable.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff concludes that this program element is

acceptable.

(3) Parameters Monitored or Inspected - In LRA Section B.1.16.1, the applicant stated that

for the "parameters monitored/inspected" program element, the primary containment

and its attachments are inspected for evidence of cracks, wear, and corrosion.

The staff determined that the applicant's program element "parameters

monitored/inspected" are identified and linked to the degradation of its intended

functions. This satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. On this

basis, the staff found that the applicant's description of the "parameters

monitored/inspected" is acceptable.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A. 1.2.3.3. The staff concludes that this

program element is acceptable.

(4) Detection of Aging Effects - In LRA Section B.1.16.1, the applicant stated that for the

"detection of aging effects" program element, the Containment Inservice Inspection

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Program manages loss of material and cracking for the primary containment and its

integral attachments.

The primary inspection method for the primary containment and its integral attachments

is visual examination. Visual examinations are performed either directly or remotely, with

sufficient illumination and resolution suitable for the local environment, to assess

general conditions that may affect either the containment structure integrity or leak

tightness of the pressure-retaining component. The program includes augmented

ultrasonic examinations to measure wall thickness of the containment structure.

For steel, the Containment Inservice Inspection Program manages loss of material and

cracking for ASME Code class MC pressure-retaining steel components and their

integral attachments. This aging effect is managed by visual inspections required by

ASME Code Section XI, Subsection IWE.

During the audit and review, the staff asked the applicant to clarify what Entergy had

done to augment its ISI program requirements for IWE components and justify why the

augmented program is considered to be capable of detecting the aging effects of

concern. In its response, the applicant stated: "Augmented Containment Inspection

Program for examinations other than those required by IWE-1241, JAFNPP has

implemented a sub-tier augmented inspection plan, based on the HPCI and reactor core

isolation cooling (RCIC) actuation requiring ultrasonic examination of the torus from the

exterior surface."

The applicant stated that JAFNPP's drywell interior surfaces are examined for

degradation every outage in accordance with ASME Code Section XI, 1998 Edition with

1998 Addenda, Subsection IWE requirements for class MC and metallic liners of class

CC components of light-water cooled plants. In general, the overall coating of the steel

surface is in good condition. There are small areas (less than 2 square feet in size) of

flaking and peeled paint from various elevations, and the wall section behind the "A' and

"B" Cooling Filters shows signs of rust staining on the coating from elevation 268'-0" to

elevation 256'-6". The rust color staining is from the condensation forming on the

cooling lines to the filters. The piping behind the Cooling "A" and "B" Filters were

cleaned and two of the pipe lines were painted. However, the JAFNPP primary

containment system is inerted with nitrogen gas during normal power operations so that

oxygen levels are maintained at less than 4 percent. Inerting with nitrogen provides an

atmosphere that is not conducive to corrosion of containment interior surfaces. With

such a low oxygen level the oxidation of the steel is diminished. The staff finds

acceptable the applicant's assessment since the aging effect is managed by visual

inspections required by ASME Code Section XI, Subsection IWE and the fact that the

containment is inerted with nitrogen which provides an atmosphere that is not conducive

to corrosion of containment interior surfaces. On this basis, the staff found that the

applicant's description of the "detection of aging effects" is acceptable.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.4. The staff concludes that this program

element is acceptable.

(5) Monitoring and Trending - In LRA Section B.1.16.1, the applicant stated that for the

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"monitoring and trending" program element, the results are compared, as appropriate, to

baseline data and other previous test results. If indications are accepted for continued

use by analytical evaluation, the areas containing such flaws are monitored during

successive inspection periods.

During the audit and review, the staff asked the applicant to explain how inspections are

performed in the torus suppression pool above and below the water line and to explain

historically what-inspection findings have led JAFNPP to perform augmented

inspections. In its response, the applicant stated: "The interior torus suppression pool

area above and below the water line are inspected in accordance with the IWE program

during refueling outages. A general visual examination is performed of the area above

the water line. Below the water line is normally inaccessible unless the torus water level

is lowered or drained, for a work activity. The torus was last drained and cleaned in 1998

for the installation of the emergency core cooling system strainers. The visual

examination identified nine of the most severe areas of pitting. The depths of the pits

were measured at that time and a portion of those areas are monitored and measured

by means of UT from the outside of the torus shell every outage. Over a five years

period, all nine of the pitted areas are examined by performing UT and found to be

accepted in accordance to the Code requirements."

The staff also asked the applicant, during the audit and review, to provide any

information regarding the applicant's actions in response to GL 87-05 and other industry

operating experience including actions planned as a result of recent staff guidance

(LR-ISG-2006-01) to address the potential loss of material due to corrosion in

inaccessible areas of Mark I steel drywell liner shell for the period of extended operation.

In its response, the applicant stated: "Two inspections were required per GL 87-05 prior

to start-up from the 1988 refueling outage. The first being inspection of the eight(8) 2"

diameter sand cushion drain lines and the second being inspection of the six (6)

refueling bellows leakage drain lines. The inspections using a flexible boroscope were

performed to determine that the drains were unplugged and functioning as designed. All

,eight sand cushion drain lines were inspected and seven of the eight were found to be

operable. Five of the six refueling bellows leakage drain lines were inspected and found

to be operable. Inspection ports were installed prior to the inspection in five of six lines.

One inspection port was not installed in the sixth fine because it was inaccessible. The

sand cushion is covered with stainless steel plates and an adhesive seal to prevent

in-leakage. Drains are provided immediately above these plates and also at the bottom

of the sand cushion. Because of this design arrangement, no Ultrasonic thickness were

performed for the drywell shell plates adjacent to the sand cushion. All of the drain

connections are welded; therefore, the are no gasket inspections or maintenance

required."

During the audit and review, the staff also asked the applicant to explain, if water

leakage has ever been discovered between the drywell and concrete secondary shield

wall or in the sand pocket area. Also, to explain what JAFNPP does to inspect for water

leakage in these two areas or to verify that loss of material is not occurring on the

backside of the drywell. In its response, the applicant stated that there has been no

observed leakage causing moisture in the vicinity of the sand cushion and no moisture

has been detected or suspected on the inaccessible areas of the drywell shell. Further,

any potential leakage through the refueling bellows assembly is directed to a drain

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system. Therefore, no additional components have been identified that require an AMR

as a source of moisture that might affect the drywell shell in the lower region. In 1988,

JAFNPP also examined the air gap with a boroscope through the drain lines and did not

find any evidence of moisture in the air gap or corrosion of the drywell shell. It should be

noted that the bellows drain lines are welded in place and have no gaskets that can

leak, as existed at the Oyster Creek station.

To ensure the drywell shell exterior remains dry during refueling evolutions, the drywell

to reactor building bellows assembly separates the refueling cavity filled with water from

the exterior surface of the drywell shell. Any leakage through the bellows assembly is

directed to a drain system ((inner bellows to the Drywell Equipment Drain Sump, outer

bellows to the "B" Condensate Storage Tank), where two lines are each equipped with a

flow indicator/switch that will alarm in the Control Room in the event of a bellows failure.

A Preventive Maintenance - "Test 19FIS-61 prior to initial refuel cavity flood-up" is

performed every outage to verify the indicator/switch is functional and the Control Room

annunciator responds when water is added to the line. In addition, a Preventive

Maintenance - Functional Test of 19FIS-62 is performed every two years to verify the

indicator/switch and associated Control Room annunciator are functional.

The staff finds the applicant's responses and assessments acceptable since, all

accessible surfaces are monitored by virtue of the examination requirements on a

scheduled basis. The monitoring and trending of the drywell shell liner plate are in

addition to the current JAFNPP ASME Code Section XI, Subsection IWE procedural

requirements. These inspections will provide additional assurance that there is no loss

of intended function of the drywell shell. On this basis, the staff found that the

applicant's description of the "monitoring and trending" is acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.5. The staff concludes that this program

element is acceptable.

(6) Acceptance Criteria - In LRA Section B.1.16.1, the applicant stated that for the

"acceptance criteria" program element, the results are compared, as appropriate, to

baseline data, other previous test results, and acceptance criteria of the ASME Code

Section XI, Subsection IWE, for evaluation of any evidence of degradation.

The staff reviewed this program element to determine whether or not it satisfied the

criteria defined in SRP-LR Appendix A. 1.2.3.6. In its letter dated February 12, 2007,

(Amendment 6), the applicant stated the following:

JAFNPP inspects the liner drains for the water reservoirs on the refuel floor (e.g., spent

fuel pool, dryer/separator pool, and reactor cavity) for leakage. Leakage into the liner

drain could be a precursor for water leaks, which could wet the drywell shell exterior

surface. These drains are examined for leakage after filling the refueling cavity. The

code requires owners to identify locations they believe are suspect or potential problem

areas for augmented inspection. Program at two locations in the upper drywell

immediately adjacent to the fuel pool due to the potential for leakage from the fuel pool

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liner. The drywell shell to floor joint is inspected accordance with ASME Code

Section XI, 1998 Edition with 1998 Addenda, Subsection IWE requirements for class

MC and metallic liners of class CC components of light-water cooled plants under the

JAFNPP IWE Program.

The staff found that the applicant's description of the "acceptance criteria" is consistent

with SRP-LR Section A.1.2.3.6. and is acceptable.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A. 1.2.3.6. The staff concludes that this program element is

acceptable.

(10) Operating Experience - LRA Section B.1.16.1 states that-the containment ISI general

-visual walk-down of the primary containment during R015,(2002) and R016 (2004)

revealed minor areas of peeling paint and rust scale but no significant loss of material.

Work was requested to repaint the affected areas as necessary. The torus interior

general visual inspection and torus exterior inspection and ultrasonic examination

revealed no significant loss of material or unacceptable indications. Absence of loss of

material proves that the program is effective for managing aging effects. A

self-assessment in 2004 revealed no issues or findings with impact on program

effectiveness.

The applicant stated that JAFNPP monitors torus wall thickness via the inclusion of

augmented UT thickness examinations in the JAFNPP IWE Program. During refueling

outage RFO-16 (2004), the applicant performed thickness examinations at nine pitted

locations identified during 1996 IWE examination (two at "B" bay, two at "H" bay, two at

"K" bay, and three at "0" bay around the torus). The applicant found that only three

locations were below design (0.632"), with measured pitted depths of 0.019", 0.014" and

0.010".

During the audit and review, the staff asked the applicant to address the operating

experience such as crack on the torus shell identified on June 27, 2005. In its response,

the applicant stated that " the JAFNPP torus preservation verifies that sample locations

are tracked for wall thinning. The reports are in NDE database and used to assure

adequate wall thickness. IWE examinations are performed and any discrepancies noted

in coatings are repaired using the CR system. The torus was repaired in July 2005 using

a cap and removing the damaged section of shell. The root cause analysis determined

condensation oscillation from the HPCI Turbine Steam Discharge provided the energy

that initiated the cracking. UT was subsequently performed at this location and at the

RCIC discharge each time they were run. In RFO-17 a VT was scheduled on the extend

of condition and two cracked were noted near the HPCI discharge line was modified with

a sparger assembly which is designed to eliminate condensation oscillation. JAF

documentation can be found under CR-JAF-05-2593, CR-JAF-06-4526

(WO-JAF-05-24673 and WO-JAF-06-28641, respectively). In addition, some minor

surface rust/corrosion and areas of deteriorated coatings were evaluated and found

acceptable by the responsible design engineer."-

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The applicant also stated in Amendment No. 6 to the LRA dated February 12, 2007,

that:

There has been no observed active leakage causing moisture in the

vicinity of the sand cushion drain line at JAF as monitored by IWE

general visual examination of the exterior of the torus and torus room. No

moisture has been detected or suspected on the inaccessible areas of

the drywell shell. Any leakage through the refueling bellows assembly is

directed to a drain system (inner bellows to the Drywell Equipment Drain

Sump, outer bellows to the "B" Condensate Storage Tank). Therefore, no

additional components have been identified that require AMR as a source

of moisture that may affect the drywell shell in the lower region.

In 1988, JAF examined the air gap through the drain lines using fiber

optic cables and did not have any evidence of moisture potentially

causing corrosion of the drywell shell (Reference NYPA Memorandum

No. JTS-88-0875, from V. Walz to W. Fernandez, dated November 1,

1988). JAF plans to perform an additional examination in 2007

(Reference maintenance work order WO # JAF-07-14863. If any

evidence of moisture is identified JAF will determine additional inspection

activities, as appropriate.

JAF monitors refueling bellows leakage drain lines during every refueling

outage. Flow indicator/switches 19FIS-61 and 19FIS-62 were

successfully last tested in 2006. The flow indicators/switches are on a two

year PM frequency.

Drywell interior surfaces are examined for degradation every refueling

outage in accordance with the JAF IWE Program. A general visual

examination has been performed every refueling outage looking at the

steel and concrete surfaces for shrinkage cracks in the concrete,

cracking and peeling coating, and discoloration of the surface coating

(bleed through, staining). There were areas of minor corrosion bleed

though the coating (less than 4 square feet) and staining (less than 50

square feet) caused by condensation from the "A" and "B" Cooling filter

lines. The areas of peeling and flaking paint are less than 2 square feet

areas. Engineering evaluated the minor surface condition at various

locations and were found to be acceptable. The minor degraded areas

are monitored every refueling outage.

The drywell shell to floor caulked seal is inspected every refueling

outage. A general visual examination is performed looking for cracking,

peeling, delaminating or separation of the seal, discoloration in the

caulking material, and flexibility of the caulking. The caulk seal has not

been removed or replaced.

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The staff reviewed the operating experience provided in the LRA and the above

amendment and interviewed the applicant's technical staff to confirm that the

plant-specific operating experience did not reveal any degradation not bounded by

industry experience.

The staff confirmed that the "operating experience" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element

acceptable.

UFSAR Supplement. The applicant provided its UFSAR supplement for the Containment

Inservice Inspection Program in LRA Section A.2.1.17. It outlines the requirements for the

inspection of class MC pressure-retaining components (primary containment) and their integral

,attachments in accordance with the requirements of 10 CFR 50.55a(b)(2) and ASME Code

Section Xl, 1992 Edition with no Addenda, Inspection Program B.

The primary inspection method for the primary containment and its integral attachments is

visual examination. Visual examinations are performed either directly or remotely with

illumination and resolution suitable for the local environment to assess general conditions that

may affect either the integrity of the containment structure or leak tightness of the

pressure-retaining component. The program includes augmented ultrasonic exams to measure

wall thickness of the containment drywell structure. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Containment Inservice

Inspection 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).

3.0.3.3.3 Inservice Inspection Program

Summary of Technical Information in the Application. LRA Section B.1.16.2 describes the

existing, plant-specific Inservice Inspection Program.

The Inservice Inspection Program is a plant-specific program encompassing ASME Code

Section XI, Subsections IWA, IWB, IWC, IWD and IWF requirements.

Section 50.55a of 10 CFR, imposes ISI requirements of ASME Code, Section XI, for Class 1, 2,

and 3 pressure-retaining components, their integral attachments, and supports in light-water

cooled power plants. Inspection, repair, and replacement of these components are covered in

Subsections IWB, IWC, IWD, and IWF respectively. The program includes periodic visual,

surface, and volumetric examination and leakage tests of Class 1, 2, and 3 pressure-retaining

components, their integral attachments and supports. Inservice inspection of supports for

ASME piping and components is addressed in Section XI, Subsection IWF. ASME Code

Section XI, Subsection IWF and constitutes an existing mandated program applicable to

managing aging of ASME Class 1, 2, 3, and MC supports for license renewal.

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The program uses NDE techniques to detect and characterize flaws. Three different types of

examinations are volumetric, surface, and visual. Volumetric examinations are the most

extensive, using methods such as radiographic, ultrasonic or eddy current examinations to

locate surface and subsurface flaws. Surface examinations, such as magnetic .particle or dye

penetrant testing, are used to locate surface flaws. Three levels of visual examinations are

specified. VT-1 visual examination is conducted to assess condition of the surface of the part

being examined, looking for cracks and symptoms of wear, corrosion, erosion or physical

damage. It can be done with either direct visual observation or with remote examination using

various optical/video devices. The VT-2 examination is conducted specifically to locate evidence

of leakage from pressure retaining components (period pressure tests). While the system is

under pressure for a leakage test, visual examinations are conducted to detect direct or indirect

indication of leakage. The VT-3 examination is conducted to determine the general mechanical

and structural condition of components and supports and to

detect discontinuities and imperfections.

The Inservce Inspection Program is based on ASME Inspection Program B (IWA-2432), which

has 10-year inspection intervals. Every 10 years the program is updated to the latest ASME

Section XI code edition and addendum in accordance with 10 CFR 50.55a. On September 28,

1997, JAFNPP entered the third ISI interval. The ASME code edition and addenda used for the

third interval is the 1989 Edition with no addenda. The current program ensures that the

structural integrity of Class 1, 2, and 3 systems and associated supports is maintained at the

level required by 10 CFR 50.55a.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.1.16.2 regarding the applicant's demonstration of the Inservice

Inspection Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation.

During the audit and review, the staff reviewed the Inservice Inspection Program against the

AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, focusing its review

on how the program manages aging effects through the effective incorporation.of 10 elements

as described in SER Section 3.0.2.1. The staff also interviewed the applicant's technical staff

and reviewed program basis document which provides the bases for program element criteria

defined in SRP-LR Section A. 1.2.3.

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are parts of the site-controlled QA program. The staff's evaluation

of the QA program is discussed in SER Section 3.0.4. The remaining seven elements are

discussed below.

(1) Scope of the Program - In LRA Section B.1.16.2, the applicant stated that the Inservice

Inspection Program is credited with the management of loss of material,. cracking, and

reduction of fracture toughness properties in the piping, components, and supports of

the reactor coolant system and that the AMP implements the requirements of Section Xl

of the ASME Boiler and Pressure Vessel Code (henceforth Section XI), Subsections

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IWB, IWC, IWD, and IWF, as required by 10 CFR 50.55a. The applicant also stated that

the program includes applicable relief requests and alternative programs as approved in

accordance with 10 CFR 50.55a and that the Section XI Edition of record is updated

once every ten years.

The staff noted that the 3"V 10-Year ISI Interval for JAFNPP was the ISI interval in effect

at the time of the staff's AMP audit, which was performed during the week of

December 12-18, 2006. The staff reviewed the applicant's procedure for implementing

the ISI Program during the 3V 10-Year ISI Interval for JAFNPP reflected in quality

Procedure JAF-ISI-0002, "JAFNPP Third Ten-Year In-service Interval Inspection

Program," Revision 4, April 20, 2005. The applicant updates this procedure through the

applicant's 10 CFR 50.59 process prior to entering the subsequent 10-Year ISI Interval

for JAFNPP to ensure that the applicant will continue to implement its ISI Program in

compliance with -the requirements of 10 CFR 50.55a.

The applicant entered the 4e Ten-Year ISI Interval for JAFNPP in January 2007. The

applicant was required by 10 CFR 50.55a(g)(4)(l) to update the ASME Code, Section XI

(Section Xl code of record) to the 2001 Edition of Section XI, inclusive of the 2003

Addenda. The staff requested clarification from the applicant on whether the Section XI

code of record for the 4t Ten-Year ISI Interval is the 2001 Edition of Section Xl,

inclusive of the 2003 Addenda.

The applicant clarified that the 2001 Edition of Section XI, inclusive of the 2003 Addenda

will be the new Section XI code of record for those JAFNPP AMPs referencing or

crediting Section Xl requirements. The applicant also stated that LRA Section A.2.1.18

will be amended to delete the relevant information for the 3r 10-Year ISI Interval and to

incorporate the relevant information for the 4th 10-year ISI Interval for JAFNPP, including

a statement that the 2001 Edition of Section Xl, inclusive of the 2003 Addenda is the

applicable edition of Section XI for the 4th 10-Year ISI Interval. Use of the 2001 Edition

of the AMSE Code Section XI, inclusive of the 2003 Addenda, is consistent with edition

of the ASME Code Section Xl referenced in GALL AMP XI.M1, "ASME Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD." The applicant amended the

LRA (Amendment 5) in its letter dated February 1, 2007, in order to reflect the change in

the ASME Code Section XI edition of record referenced for the 4th 10-Year ISI Interval.

The staff concludes that the changes to the LRA are acceptable because they are in

compliance with the requirements of 10 CFR 50.55a and in conformance (i.e.,

consistent) with the "scope of program" element in GALL AMP XI.M1, "ASME Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD."

The staff determined that Procedure JAF-ISI-0002, Revision 4, provides requirements,

elements, criteria, and descriptions that if implemented, would be in compliance with the

requirements of 10 CFR 50.55a and the ASME Code Section XI for JAFNPP systems or

portions of JAFNPP systems categorized as ASME Code Class 1, 2, or 3, or their

component supports. However, the staff also determined that the applicant's "scope of

program" attribute for the ISI Program in the LRA implied that the reactor coolant

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system (RCS) was the only JAFNPP system within the scope of the ISI program and

that the Section Xl requirements in Subsections IWB, IWC, IWD, and IWF applied to the

components in all portions of the RCS.

The staff reviewed the AMR tables for the RCS, emergency safety feature systems,

auxiliary systems, and steam and power conversion system in the LRA and confirmed

that the applicant's ISI Program is credited only with aging management of particular

commodity groups in the AMR tables for the RCS (i.e., in LRA AMR Tables 3.1.2-1,

3.1.2-2, and 3.1.2-3). The staff sought further clarification about the other systems and

components that are within the ISI program and their ASME code classifications. During

the audit and review, the staff asked the applicant to identify all JAFNPP systems and

components that are within the scope of the ISI and to identify exactly which ASME

Code Classifications were applicable to these systems and components.

The applicant clarified in its response that the systems within the scope of the ISI

Program include:

* flow diagram reactor building service water cooling system

* control room area-service and chilled water system

* reactor building. cooling water system

* pass cooling water supply system

* fuel pooling cooling (FPC) system

* core spray (CS) system

* SLC system

* RCIC system

* RWCU system

* RHR system

• HPCI system

* reactor water recirculation system

* CRD system

* • feedwater system

* service water (SW) system

• emergency service water (ESW) system

* nuclear boiler vessel instrumentation (NBVI)

* emergency diesel generator fuel oil and combustion air systems

* emergency diesel generator and lubricating systems

* emergency diesel generator air start-up lines

The applicant, in addition, confirmed that the ISI program also incorporates Section Xl

requirements pursuant tolO CFR 50.55a for the portions of these systems that are part

of the reactor coolant pressure boundary (i.e., that are categorized ASME Code Class 1)

and for systems or portions of systems categorized as ASME Code Class 2 and 3, even

though the program is not credited for aging management for ASME Code Class 2 and

3 systems and components or their component supports. The scope of the AMP also

includes the component supports for ASME Code Class 1, 2, and 3 components. This is

in compliance with 10 CFR 50.55a and is acceptable.

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JAFNPP completed its 3rd Ten-Year ISI Interval for the plant in December 2006 and

entered the 4t 10-Year ISI Interval in January of 2007.

In RAI B.1.16.2-1 dated November 7, 2006, the staff informed the applicant that the

staffs approval of any alternative programs or relief requests granted for these 10-Year

intervals do not extend into the period of extended operation for JAFNPP or its two

10-year ISI intervals (i.e., do not extend into the 5t and 6' 10-year ISI intervals for the

plant).

The staff asked the applicant to either amend the LRA to remove any reference to past

staff-approved relief requests or alternative ISI provisions or else provide a commitment

on the LRA that if relief requests or alternative programs are sought for the period of

extended operation, the relief requests or alternative programs will be submitted for staff

review and approval pursuant to the applicable requirements of 10 CFR 50.55a, unless

they have been incorporated in the code of record for JAFNPP or are covered by

endorsed code cases.

* In a letter dated February 1, 2007 (Amendment 5), the applicant provided its response

to RAI B.1.16.2-1. In its response, the applicant removed the reference to the relief

requests or alternative ISI provisions via amending LRA Section B.1.16.2.

This staff finds the applicants response to RAI B.1.16.2-1 acceptable because the relief

requests or alternative programs will be submitted for staff review and approval pursuant

to the applicable requirements of 10 CFR 50.55a.

Based on this assessment, the staff concludes that the scope of the ISI program is

acceptable because the AMP is credited with the aging management of loss of material,

cracking, and reduction of fracture toughness in the components of the RCPB (i.e,

ASME Code Class 1 components) and their component supports, which is in

conformance with the AMR line items in GALL Report, Revision 1 for which this program

is recommended for aging management. In addition, the staff has confirmed that, even

though the ISI program is not credited with the aging management of the AMR

commodity groups for the emergency safety features, auxiliary systems, and S&PC

system, the scope of the program does include those portions of these systems that are

categorized as ASME Code 2 or 3, as required by 10 CFR 50.55a.

Based on this assessment, the staff concluded that the "scope of program" program

element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff concludes

that this program element is acceptable.

(2) Preventive Actions - In LRA Section B.1.16.2, the applicant stated that the ISI Program

is a condition monitoring and does not include preventive actions. ISI programs for US

commercial nuclear power plants are invoked in accordance with the requirements

Section XI, in compliance withlO CFR 50.55a. The ISI requirements of Section XI apply

staff-approved NDE methods to inspect for degradation or age-related aging effects that

could impact the structural integrity of ASME Code Class 1, 2, and 3 components and

their component supports. The ISI requirements of Section Xl do not involve required

activities which prevent or mitigate these degradation effects or age-related aging

effects from occurring.

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Instead, the applicant implements its water chemistry program as the basis for

mitigating the corrosive mechanisms that could induce loss of material or cracking in the

ASME Code Class 1, 2, and 3 components at JAFNPP. The staff evaluates the ability of

the applicant's water chemistry program .to mitigate the aging effects that are applicable

to ASME Code Class 1, 2, and 3 components in SER Section 3.0.3.1.10.

Therefore, the staff finds it acceptable that the scope of the ISI Program for JAFNPP

does not include preventive actions. Based on this assessment, the staff concludes that

the "preventive actions" program element need not conform to the "preventive actions"

program attribute criterion defined in SRP-LR Section A.1.2.3.2 and that the applicant's "preventive actions" program attribute description for the ISI Program is acceptable.

(3&4) Parameters Monitored or Inspected and Detection of Aging Effects - In LRA

Section B.1.16.2, the applicant stated that

the ISI program manages cracking, loss of material, and

reduction in fracture tough in reactor coolant system components

made from carbon steel, low alloy steel, low alloy steel with

stainless steel cladding, stainless steel, and nickel-based alloy

materials.

ISI programs for U.S. commercial nuclear plants are based on the requirements of

10 CFR 50.55a, which invokes the ISI examinations in Section XI for components

categorized as ASME Code Class 1, 2, and 3 components and their component

supports. Section XI, Subsection IWA-2000 identifies particular NDE techniques to

manage the mechanisms that could potentially lead to loss of material or cracking of

ASME code Class 1, 2, and 3 components and their component supports. The staff

concludes that it is acceptable to use the ISI program as an appropriate AMP for

managing loss of material and cracking in these components because the mechanisms

which could potentially lead to these aging effects are in compliance with those

monitored for by the NDE methods invoked by Section XI, Subsection IWA-2000. These

NDE methods are discussed in more detail later in this section.

As indicated in LRA Table 3.1.2-3, the applicant credits the ISI Program to manage

reduction of fraction toughness in the following Class 1 commodity groups: (1) Class 1

pump casings and covers fabricated from cast austenitic stainless steel (CASS), and (2)

Class 1 pump casing thermal barriers fabricated from CASS, (3) Class 1 CASS valve

bodies less than 4 inches NPS made from CASS, and (4) Class 1 CASS valve bodies

less than or equal to 4 inches NPS. Fracture toughness is a material property that is

indicative of a material's ability to resist crack initiation. The fracture toughness of a

material is normally established by drop weight or Charpy-V impact testing and analysis.

During the audit and review, the staff asked the applicant to clarify how the ISI program

monitors for reduction (loss) of fracture toughness since the fracture toughness cannot

be monitored by inspection methods.

Reduction of the fracture toughness property in CASS materials may occur by a

mechanism known as thermal aging, in which the material embrittles as result of being

exposed to high temperatures over a prolonged period of time. The applicant clarified in

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its response that the staff's position in its letter of May 19, 2000, from C. Grimes (NRC)

to D. Walters (Nuclear Energy Institute [NEI]) will be used to manage reduction of

fracture in these CASS pump casing and valve body components.

In its letter of May 19, 2000, the staff established its position that:

(1) CASS valves bodies and pump casing components "are adequately covered by

existing inspection requirements in Section XI ..., including the alternative requirements

of ASME Code Case N-481 for pump casings," and (2) "screening for susceptibility to

thermal aging is not required." Based on this assessment, the applicant provided an

acceptable basis for explaining how reduction of fracture.toughness will be managed by

the ISI Program in that the applicant is applying the staff's position in the staff letter of

May 19, 2000, for managing potential reduction of fracture toughness due/thermal aging

in the Class 1 CASS valve bodies and pump casing components.

In LRA Section B.1.16.2, the applicant also stated that "the ISI Program uses NDE

examination techniques to monitor for and detect the aging effects that are applicable to

the components within the scope of the program. The applicant -stated that these NDE

techniques include: (1) volumetric examination techniques such as radiography testing

(RT), ultrasonic testing (UT), and eddy current testing (ET), (2) surface examination

techniques, such as dye penetrant testing (PT) and magnetic particle testing (MT), and

(3) visual examination methods, including ASME VT-i, VT-2, and VT-3 visual

examination techniques. Of the visual inspection methods available for use, the

applicant clarified in the LRA that:

(1) VT-1 techniques are used to assess the condition of the surface of the

component being examined and to monitor for evidence of cracking, wear,

corrosion, erosion, or physical damage

(2) VT-2 techniques are used to locate evidence of leakage from AMSE Code Class

pressure boundary components

(3) VT-3 techniques are used to determine the general mechanical and structural

condition of components and supports and to detect discontinuities and

imperfections.

ASME Code Section XI, Article IWA-2000,specifies that the NDE methods for ASME

Code Class 1, 2, and 3 components and their component supports include the following

techniques:

* volumetric techniques: radiography (RT), ultrasonic testing (UT), and eddy

current testing (ET)

* surface examination techniques: magnetic particle testing (MT) and penetrant

testing (PT)

" visual examination methods: ASME VT-i, VT-2, and VT-3 methods.

Of these NDE methods, the staff reviewed the NDE techniques invoked by Section XI,

Subsection IWA-2000 and determined that this ASME subsection specifies that RT, UT,

ET, PT, RT, and VT-1 (including enhanced VT-1 [EVT-1] are capable of monitoring for

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and identifying loss of material and cracking in ASME Code Class components. The

staff also determined that ASME Subsection IWA-2000 specifies that VT-3 visual

methods are capable of monitoring and identifying indications of loss of material in these

components and that VT-2 visual methods are limited to monitoring for and identifying

indications of leakage that may result from loss of component integrity.

The staff also determined that the criteria in JAFNPP Procedure JAF-ISI-0002,

Revision 4, invoked the NDE methods in Section XI Article IWA-2000 for managing loss

of material and cracking in ASME Code Class 1, 2, and 3 components and their

component supports and the test and analysis criteria in Section XI for managing

reduction of fracture toughness in the materials used to fabricate ASME Code Class 1

components or their component supports. This is acceptable because the applicant is

using the appropriate criteria in Section XI for managing loss of material, cracking, and

reduction of fracture toughness, as required by 10 CFR 50.55a.

Based on this assessment, the staff concludes that the applicant has appropriately

identified the aging effects managed by the ISI Program for the period of extended

operation and the techniques that may be used to manage loss of material, cracking,

reduction of fracture toughness in ASME Code Class 1, 2, and 3 components and their

component supports.

Based on this assessment, the staff confirmed that the "detection of aging effects" and

"parameters monitored or inspected" program elements satisfy the criteria defined in

SRP-LR Section A.1.2.3.3. The staff concludes that these program elements are

acceptable.

(5) Monitoring and Trending - In LRA Section B.1.16.2, the applicant stated that

... results are compared, as appropriate, to baseline data and other

previous test results. Indications are evaluated in accordance with ASME

Section XI. If the component is qualified as acceptable for continued

service, the area containing the indication is reexamined during

subsequent inspection periods. Examinations that reveal indications that

exceed the acceptance standards are extended to include additional

examinations in accordance with ASME Section XI. ISI results are

recorded every operating cycle and provided to the NRC every period via

Owner's Activity Reports. These detailed reports include scope of

inspection and significant inspection results.

ASME Code Section XI includes series of tables that specify the NDE requirements for

performing ISI of ASME Code Class 1, 2, and 3 components and their component

supports. These tables are subdivided into specific examination categories and

inspection items that specify the NDE methods, NDE sample sizes, and NDE

frequencies for performing the required ISI examinations. These tables include:

Table IWB-2500-1 of Section XI, Subsection IWB-2000 for components that are

part of the reactor coolant pressure boundary (ASME Code Class 1 or ASME

Safety Class A components).

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Table IWC-2500-1 of Section XI, Subsection IWC-2000 for components that are

categorized as ASME Code Class 2 components (ASME Safety Class C

components).

" Table IWD-2500-1 of Section XI, Subsection IWD-2000 for components that are

categorized as ASME Code Class 2 components (ASME Safety Class D

components).

" Table IWF-2500-1 of Section XI, Subsection IWF-2000 for ASME Code Class

component supports.

The staff reviewed JAFNPP ISI Procedure JAF-ISI-0002, Revision 4, and confirmed that

the procedure invokes the appropriate tables listed above for ASME Code Class 1, 2,

and 3 components, the applicable examination: categories and inspection items invoked

by these tables, and the NDE methods, frequencies,: and sample sizes required by

these ISI examination categories and inspection items. The applicant's ISI program

provides an acceptable basis for monitoring and trending for indications of loss of

material and cracking because it invokes the NDE methods, frequencies, and sample

sizes for ASME Code Class components and component supports required by

Section XI, in accordance with10 CFR 50.55a. The ISI Program also analyzes for

reduction in the fracture toughness properties in the materials of components that are

susceptible to neutron irradiation embrittlement or thermal aging. In addition, the ISI

Program will also ensure that any cracks will be detected before they grow to a size in

excess of the allowable flaw size (i.e., critical crack size) permitted by fracture

toughness analysis.

Based on this assessment, the staff confirmed that the"monitoring and trending"

program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5. The staff

concludes that this program element is acceptable.

(6) Acceptance Criteria - In LRA Section B.1.16.2, the applicant stated that

... a preservice, or baseline, inspection of program components was

performed prior to startup to assure freedom from defects greater than

code-allowable. This baseline data also provides a basis for evaluating

subsequent inservice inspection results. Since plant startup, additional

inspection criteria for Class 2 and 3 components have been imposed by

10 CFR 50.55a for which baseline and inservice data has also been

obtained. Results of inservice inspections are compared, as appropriate,

to baseline data, other previous test results, and acceptance criteria of

the ASME Section Xl, 1989 Edition, no Addenda, for evaluation of any

evidence of degradation.

In its letter dated February 1, 2007, the applicant clarified that the 2001 Edition of

Section XI, inclusive of the 2003 Addenda will be the new Section XI code of record for

those JAFNPP AMPs referencing or crediting Section Xl requirements. The applicant

also stated that LRA Section A.2.1.18 will be amended to delete the relevant information

for the 3rd 10-Year ISI Interval and to incorporate the relevant information for the 4 th

10-year ISI Interval for JAFNPP, including a statement that the 2001 Edition of

Section XI, inclusive of the 2003 Addenda is the applicable edition of Section XI for the

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4 ' 10-Year ISI Interval. The applicant amended the LRA (Amendment 5) in a letter

dated February 1, 2007.

ASME Code Section XI includes particular flaw evaluation methods and acceptance

criteria for evaluating flaws that are detected during the implementation of required ISI

examinations. These methods and criteria include prescribed methods for sizing the

flaws based on the ISI examinations results and flaw size acceptance criteria. The

methods and acceptance criteria are given in the following ASME Code Section XI

subsections:

Article IWA-3000, which provides general "Standards for Evaluation

Examinations"

Article IWB-3000, which provides "Acceptance Standards for Flaw Indications" in

ASME Code Class 1 components

Article IWC-3000, which provides "Acceptance Standards for Flaw Indications" in

ASME Code Class 2 components

Article IWD-3000, which provides "Acceptance Standards for Flaw Indications" in

ASME Code Class 3 components

Article IWF-3000, which provides "Acceptance Standards for Flaw Indications" in

ASME Code Class component supports

The applicant stated that if flaws are detected during an ISI examination, the flaws are

evaluated for acceptance in accordance with the general acceptance criteria provisions

of Section Xl, Article IWA-3000 and the applicable provisions in Section XI Article

IWB-3000, IWC-3000, IWD-3000, or IWF-3000, as applicable to the component's ASME

classification. This is acceptable because the applicant is applying the evaluation and

acceptance criteria of Section XI to the ASME Code Class 1, 2, and 3 components

within the scope of the ISI program.

The staff confirmed that the"acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6. The staff concludes that this program element is

acceptable.

(10) Operating Experience - LRA Section B. 1.16.2 states that "ISIs during R015 (2002)

detected a pipe support with as-built configuration discrepancies which were accepted

by evaluation and reflected on applicable drawings. A visual inspection also detected

loose spring and pipe support clamp nuts that were subsequently tightened. ISIs during

RFO16 (2004) detected a few pipe supports with as-built configuration discrepancies

which were accepted by evaluation and reflected on applicable drawings. Ultrasonic

examination of a feedwater pipe-to-valve weld detected a subsurface planer indication

which was accepted by evaluation. A self-assessment in 2004 revealed no issues or

findings with impact on program effectiveness."

The staff reviewed the applicant's operating experience summaries in the operating

experience reports.

During the audit and review, the staff asked the applicant to identify all relevant

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operating experience that is relevant to the JAFNPP ISI Program and was used to

augment the requirements of the ISI Program, other than the augmented inspection and

flaw evaluation guidelines for the reactor vessel and its internals, which are evaluated in

SER Section 3.0.3.2.7.

The applicant identified in its response that the following augmented inspections are

performed at JAFNPP based on programmatic requirements or operating experience

results for JAFNPP.

Risk-informed inspections of pressure retaining dissimilar metal welds in Class 1

components (i.e., bimetallic welds or inconel alloy welds, such as those made

from Alloy 82, 182, 52, or 152) in accordance with Section Xl Category B-F,

including inspections for the occurrence of intergranular stress corrosion

cracking (IGSCC)

Risk-informed inspections of pressure retaining in Class 1 piping components in

accordance with Section XI Category B-J, including inspections for the

occurrence of IGSCC

Risk-informed inspections of pressure retaining in Class 2 piping components in

accordance with Section XI Category C-F, including inspections for the

occurrence of IGSCC

" augmented examinations of core spray pump discharge piping welds that are

considered to be potentially susceptible to vibration-induced cracking (i.e., high

cycle fatigue-induced cracking)

" augmented inspection of the Class 1 feedwater (FW) nozzles in accordance with

the requirements of Section XI IWB and the industry recommendations in

General Electric (GE) Report NE-523-A71-0594.

The applicant stated that an IS[ examination of feedwater pipe-to-pump weld 18-34-289

identified the presence of a subsurface planer flaw in the component. The applicant

stated that an evaluation of the flaw was performed and that the evaluation indicated

that the flaw was acceptable for further service.

The staff determined that this is acceptable because it provides the relevant operating

experience that resulted in enhancement and augmentation of the applicant ISI

program.

During the audit and review, the staff also asked the applicant to clarify what type of

analysis, if any, was performed in evaluation of this flaw, and, if applicable, to identify

whether or not the evaluation of the flaw indication was a TLAA in accordance

with10 CFR 54.3.

In its response, the applicant stated that the UT inspection result that had identified the

flaw indication was correlated back to a slag inclusion that was originally identified

during the construction radiograph (i.e., RT examination) of this pipe weld and that the

UT results were determined to be acceptable in accordance with Section XI,

paragraph IWB-3112(b).

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The staff determined that there is no associated flaw growth evaluation and it meets the

Section XI paragraph IWB-3112(b) requirements. Based on this, the staff concludes that

this flaw does not have to be treated as TLAA, because there is no flaw evaluation

associated with this slag inclusion.

The staff confirmed that the"operating experience" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.10 and found this program element

acceptable.

UFSAR Supplement. In LRA Section A.2.1.18 and in LRA Amendment No. 5, dated February 1,

2007, the applicant provided the UFSAR supplement for the Inservice Inspection Program. The

staff reviewed this section and determined that the information in the UFSAR supplement

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Inservice Inspection 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).

3.0.3.3.4 Periodic Surveillance and Preventive Maintenance Program

Summary of Technical Information in the Application. LRA Section B.1.22 describes the existing

plant-specific Periodic Surveillance and Preventive Maintenance Program.

This program includes periodic inspections and tests that manage aging effects not managed

by other AMPs. Preventive maintenance and surveillance are generally implemented through

repetitive tasks or routine monitoring of plant operations. The program takes credit for AMR of

the following systems and structures:

Reactor building Perform visual or other non-destructive examination to manage loss of

material for carbon steel components within the reactor building battery

racks framing, reactor building crane, rails, and girders, equipment access

lock doors, and refueling platform.

Reactor building Perform visual inspection and manually flex a representative sample of the

elastomer seals for equipment lock doors at reactor track bay inner & outer

doors to manage cracking and change in material properties.

Core spray system Monitor core spray piping per the existing augmented flow accelerated

corrosion program.

Automatic depressurization system Use visual or other NDE techniques to inspect torus to manage loss of

material for carbon steel piping and T-quenchers in the waterline region of

the torus.

High pressure coolant injection Monitor HPCI piping per the existing augmented flow accelerated corrosion

(HPCI) system program.

Reactor core isolation cooling Monitor RCIC piping per the existing augmented flow accelerated corrosion

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(RCIC) system program.

Standby gas treatment (SGT) Use visual or other NDE techniques to inspect a representative sample of

system internal surfaces of the valve bodies and piping in the demister drains and in

drain piping downstream of the fans to manage loss of material.

Use visual or other NDE techniques to inspect a representative sample of

internal surfaces of piping and valves in the vent piping and from the stack

analyzer sample chambers including loop seals.

Use visual or other NDE techniques to inspect a representative sample of

internal surfaces of piping downstream of the SGT fans between the drain

and the outlet of the stack sump.

Use visual or other NDE techniques to inspect a representative sample of

internal surfaces of piping, valves and flow elements in the discharge piping

from the steam packing exhauster and the condenser air removal pumps to

the SGT discharge piping to the stack.

Primary containment atmosphere Use visual or other NDE techniques to inspect a representative sample of

control and dilution system heat exchanger coil external surfaces on 27E-1A/B, 27NV-A/B, 27PBC-1 A/B

Emergency diesel generator Use visual or other NDE techniques to inspect a representative sample of

system EDG intake air, air start, and exhaust components to manage loss of

material (air start and exhaust) fouling, loss of material, cracking,*and

change in properties (intake air), and cracking (exhaust).

Heating, ventilation, and air Visually inspect and manually flex a representative sample of the HVAC

conditioning (HVAC) systems duct flexible connections to manage cracking and change in material

properties.

Use visual or other NDE techniques to inspect a representative sample of

coils, housings, drip pans, and fins to manage loss of material and to

manage fouling of the tubes and fins for air handling units (AHU) 70AHU-3A

& B, 70AHU-12A & B, 70AHU-19A, B.

Test chiller performance and. inspect tube external surfaces to manage loss

of material and fouling for heat exchanger portions of control and relay room

chillers 70RWC-2A(EVP), 70RWC-2B(EVP).

Test chiller performance and inspect tube external surfaces to manage loss

of material and fouling for heat exchanger portions of control and relay room

chillers 70RWC-2A(CND), 70RWC-2B(CND).

Plant drains system Use visual or other NDE techniques to inspect a representative sample of

the floor drain components that provide a drain path for fire suppression

water from floor drains to the floor drain collection tank or to the yard drain

system to manage loss of material.

Radwaste Use visual or other NDE techniques to inspect a representative sample of

internal surfaces of X-18 and X-19 penetration components to manage loss

of material.

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Security generator system Use visual or other NDE techniques to inspect a representative sample of

security generator exhaust components to manage cracking and loss of

material on internal surfaces.

Perform security generator operability test to manage fouling for heat

exchanger tubes.

Use visual or other NDE techniques to inspect the surface condition of the

radiator tubes to manage loss of material on external surfaces.

Nonsafety-related systems Use visual or other NDE techniques to inspect a representative sample of

affecting safety-related systems radioactive waste, circulating water, turbine closed loop cooling, raw water

treatment, contaminated equipment drain, service water, turbine building

ventilation, administration building ventilation and cooling, plumbing,

sanitary and lab, and city water system components to manage internal loss

of material.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.1.22 regarding the applicant's demonstration of the Periodic

Surveillance and Preventive Maintenance Program to ensure that the effects of aging, as

discussed above, will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation.

The staff interviewed the applicant's technical staff and reviewed program basis document

which provides an assessment for each of the AMP elements.

During the audit and review, the staff reviewed the Periodic Surveillance and Preventive

Maintenance Program against the AMP elements found in SRP-LR Section A. 1.2.3 and

SRP-LR Table A.1-1, focusing its review on how the program manages aging effects through

the effective incorporation of 10 elements (i.e., "scope of program," "preventive actions,"

"parameters monitored or inspected," "detection of aging effects," "monitoring and trending,"

"acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and

"operating experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are parts of the site-controlled QA program. The staff's evaluation

of the QA program is discussed in SER Section 3.0.4. The remaining seven elements are

discussed below.

(1) Scope of the Program - In LRA Section B.1.22, the applicant stated that the JAFNPP

Periodic Surveillance and Preventive Maintenance Program, with regard to license

renewal, includes those tasks credited with managing aging effects identified in AMRs.

The staff reviewed the applicant's program basis document for this program and noted

that Attachment 3 includes a table that identifies the plant surveillance and PM activities

included in the program, along with the components inspected or maintained, and the

parameters monitored to address aging effects. The table also includes a description of

the surveillance or PM activities that will be performed, and the acceptance criteria that

will be used to determine if the component's condition is acceptable. The staff reviewed

this table and determined that it includes sufficient detail to define the scope of this

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AMP. The scope includes components that are consistent with those in the LRA for

which this program is credited. Therefore, the staff finds this acceptable.

The staff noted that the scope of this program includes components and aging effects

that would be addressed under GALL AMP XI.M23, "Inspection of Overhead Heavy

Load and Light Load Handling Systems," and GALL AMP XI.M38, "Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components." However, the applicant

doe, not have AMPs that correspond to GALL AMPs XI.M23 and XI.M38.

During the audit and review, the staff asked the applicant to provide additional

information to justify crediting this Periodic Surveillance and Preventive Maintenance

(PSPM) AMP instead of implementing AMPs that correspond to GALL AMPs XI.M23

and XI.M38.

In response, the applicant stated that reactor building steel crane structural girders used

in load handling are inspected under the PSPM program, while process facility crane

rails and girders are inspected under the Structures Monitoring Program. The Structures

Monitoring Program will be enhanced, as identified in LRA Section B. 1.27, to address

crane rails and girders. These programs when enhanced will include visual inspections

of the crane rails and girders consistent with GALL AMP XI.M23 to manage loss of

material. Therefore the aging management activities for crane rails and girders under

the above two programs will be consistent with the attributes described for the program

in GALL AMP XI.M23 during the period of extended operation. With regard to GALL

AMP XI.M38, the applicant stated that aging management activities for internal steel

piping, piping components, and ducting included in the PSPM program include periodic

visual inspections, and are consistent with the attributes described for GALL

AMP XI.M38.

The staff reviewed Attachment 3 of the applicant's program basis document and verified

that the applicant's PSPM program includes inspections of the reactor building crane

structural girders that are consistent with the activities in GALL AMP XI.M23. Aging of

process facility crane rails and girders will be managed by the applicant's Structures

Monitoring Program. The PSPM program includes periodic visual inspections of these

components to detect surface degradation. The program includes acceptance criteria,

which state that if any significant surface corrosion or wear is detected, corrective

actions will be taken. The staff determined that these activities are consistent with GALL

AMP XI.M23, and are acceptable.

In addition, the staff review of program basis document determined that the applicant's

PSPM program includes visual inspections of the internal surfaces of steel piping, piping

components, ducting, and other components to detect aging degradation, which is

consistent with GALL AMP XI.M38 for the components and aging effects for which the

AMP is credited. These inspections are performed as part of routine surveillance tests or

maintenance, as recommended in the GALL Report. The staff finds the use of the

PSPM program in lieu of GALL AMPs XI.M23 and XI.M38 acceptable since it includes

equivalent activities to manage the aging effects being addressed.

The staff confirmed that the "scope of program" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.1. The staff concludes that this program element is

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acceptable.

(2) Preventive Actions - In LRA Section B.1.22, the applicant stated that inspection and

testing activities used to identify component aging effects do not prevent aging effects.

However, activities are intended to prevent failures of components that might be caused

by aging effects.

The staff reviewed the applicant's program basis document and noted that Attachment 3

includes a table that identifies the plant surveillance/PM activities included in the

program, along with the components inspected or maintained, and the parameters

monitored to address aging effects. The table also includes a description of the

surveillance or PM activities that would be performed, and the acceptance criteria that

would be used to determine if the component's condition is acceptable.

The staff reviewed this table and determined that the PSPM program includes both

preventive actions, as well as condition monitoring activities. The PSPM program

includes primarily inspection and testing activities, such as visual or other NDE

inspections, along with operability testing of components to monitor the condition of the

components and provide an indication that aging degradation is not occurring. These

activities are performed as part of routine surveillance testing, and are effective at

detecting degradation. The preventive actions include routine maintenance activities,

such as cleaning of chiller coils, that may prevent aging degradation from occurring, as

well as provide an opportunity to detect any degradation that has occurred. These

activities are performed as part of routine maintenance at the plant. The staff

determined that these activities will provide for the timely detection of aging degradation

and are acceptable.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A. 1.2.3.2. The staff concludes that this program element is

acceptable.

(3) Parameters Monitored or Inspected - In LRA Section B.1.22, the applicant stated that

this program provides instructions for monitoring structures, systems, and components

to detect degradation. Inspection and testing activities monitor various parameters

including system flow, system pressure, surface condition, loss of material, presence of

corrosion products, and signs of cracking.

The staff reviewed the applicant's program basis document and noted that Attachment 3

includes a table that identifies the plant surveillance/PM activities included in the

program, along with the components inspected or maintained, and the parameters

monitored to address aging effects. The table also includes a description of the

surveillance or PM activities that would be performed, and the acceptance criteria that

would be used to determine if the component's condition is acceptable.

The staff reviewed this table and determined that the parameters monitored or inspected

to manage aging primarily include surface condition to detect loss of material, cracking,

fouling, or change in properties. The specific parameter monitored is dependent upon

the component being inspected. These parameters are effective indicators of aging

degradation for components exposed to air or water environments. In some cases,

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performance testing of components is performed to confirm acceptable performance.

This is also an effective indicator of aging degradation since significant degradation will

result in poor performance or a failure to perform. The staff finds that the parameters

monitored will provide effective indications of aging degradation for the aging effects

being addressed and are acceptable.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A. 1.2.3.3. The staff concludes that this

program element is acceptable.

(4) Detection of Aging Effects - In LRA Section B.1.22, the applicant stated that PM

activities and periodic surveillances provide for periodic component inspections and

testing to detect aging effects. Inspection intervals are established such that they

* provide timely detection of degradation. Inspection intervals are dependent on

-component material and environment and take into consideration industry and

plant-specific operating experience and manufacturers' recommendations. Each

inspection or test occurs at least once every ten years. The extent and schedule of

inspections and testing assure detection of component degradation prior to loss of

intended functions. Established techniques such as visual inspections are used.

The staff reviewed the applicant's program basis document and noted that Attachment 3

includes a table that identifies the plant surveillance/PM activities included in the

program, along with the components inspected or maintained, and the parameters

monitored to address aging effects. The table also includes a description of the

surveillance or PM activities that would be performed, and the acceptance criteria that

would be used to determine if the component's condition is acceptable.

The staff reviewed this table and determined that it includes the activities that will be

used for the detection of aging. The inspection activities include visual inspections or

other NDE techniques of a representative sample of components to detect loss of

material, cracking, or fouling. Visual inspection is a proven technique for the detection of

aging degradation, particularly when it is performed during maintenance when

components can be disassembled. Performance testing of components is also included

as a condition monitoring technique. This is also an effective indicator of aging

degradation since significant degradation will result in poor performance or a failure to

perform. The inspections and tests are performed as part of routine plant surveillance

testing; therefore, the sample size and frequencies for these activities are in accordance

with plant requirements and technical specifications. The staff determined that the

inspection and testing frequencies are established based upon component material and

environment, as well as operating experience, and will provide timely detection of

degradation so that corrective actions can be taken prior to the loss of component

intended function. The staff finds that the activities included to detect aging effects will

provide timely detection of aging degradation for the aging effects being addressed and

are acceptable.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.4. The staff concludes that this program

element is acceptable.

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(5) Monitoring and Trending - In LRA Section B.1.22, the applicant stated that PM and

surveillance testing activities provide for monitoring and trending of aging degradation.

Inspection and testing intervals are established such that they provide for timely

detection of component degradation. Inspection and testing intervals are dependent on

component material and environment and take into consideration industry and

plant-specific operating experience and manufacturers' recommendations.

The staff reviewed the applicant's program basis document and verified that the

program includes monitoring and trending activities that provide for timely detection of

aging effects. The monitoring and trending activities include comparison of results to

acceptance criteria and to past results to develop predictions of degradation rates.

These predictions are used to confirm that loss of component function will not occur

prior to the next inspection. These monitoring and trending activities are included as part

of the routine plant surveillance testing and PM requirements. Inspection intervals are.

established based upon component material and environment, as well as industry and

plant-specific operating experience and manufacturers' recommendations. The staff

finds that the use of predicted degradation rates and appropriate inspection intervals will

allow for effective management of aging. The staff finds that the monitoring and trending

activities included will provide timely detection of aging degradation for the aging effects

being addressed and are acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.5. The staff concludes that this program

element is acceptable.

(6) Acceptance Criteria - In LRA Section B.1.22, the applicant stated that periodic

surveillance and PM program acceptance criteria are defined in specific inspection and

testing procedures. The procedures confirm component integrity by verifying the

absence of aging effects or by comparing applicable parameters to limits based on

applicable intended functions established by plant design basis.

The staff reviewed the applicant's program basis document and noted that Attachment 3

includes a table that identifies the plant surveillance/PM procedures included in the

program, along with the components inspected or maintained, and the parameters

monitored to address aging effects. The table also includes a description of the

surveillance or PM activities that will be performed, and the acceptance criteria that will

be used to determine if the component's condition is acceptable.

The staff reviewed this table and determined that it includes an acceptable description of

the acceptance criteria that will be used to determine if corrective actions are needed, or

if modifications to the inspection intervals are required. For surface inspections, the

acceptance criteria will be the absence of any significant indication of degradation.

Indications of degradation will require corrective actions be taken. This is an appropriate

acceptance criteria for surface inspections, which focus on the detection of degradation,

such as loss of material, cracking, or fouling. The acceptance criteria for performance

testing are based on acceptable performance limits, which are established in plant

operating requirements. This is appropriate for the performance testing of components

since the acceptance criteria must be consistent with plant surveillance testing

procedures. The staff finds the acceptance criteria appropriate for the aging effects

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being addressed.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6. The staff concludes that this program element is

acceptable.

(10) Operating Experience - LRA Section B.1.22 states that in September 2004 inspection of

the battery racks A and B carbon steel framing revealed the racks in good condition with

no signs of corrosion. In November 2005, battery rack inspections noted no signs of

corrosion; however, paint was touched up in areas where acid residue had degraded the

paint on the battery racks. During 2005, refueling platform carbon steel components

exhibited no significant corrosion or wear during exercise and inspection of the refuel

bridge. An inspection of the reactor building crane in July of 2004 revealed no significant

corrosion or wear. Absence,of aging effects proves that the program is effective for

managing loss of material on the battery racks, the refueling platform components, and

the reactor building crane, crane rails, and girders.

Inspections of reactor building doors seals between September 2005 and April 2006

detected one damaged door seal. A CR and a work order were issued to repair or

replace the seal. Detection of degradation and prompt corrective action prove that the

program is effective for managing aging effects for the door seals.

Augmented flow-accelerated corrosion program inspections in 2004 of HPCI piping

susceptible to erosion revealed measured wall thicknesses greater than 87.5 percent of

nominal wall thickness. Absence of significant wall loss proves that the program is

effective for managing loss of material on the HPCI piping. Augmented flow-accelerated

corrosion program inspections in 2002 of RCIC piping susceptible to erosion detected

three of the four locations with measured wall thicknesses greater than 87.5 percent of

nominal wall thickness. The pipe downstream of 13MOV-27 had a measured wall

thickness less than 87.5 percent of nominal wall thickness but was evaluated through

the corrective action process and found acceptable for continued use. Detection of

degradation and prompt corrective action prove that the program is effective for

managing loss of material on the RCIC piping. Inspections of EDG air intake, air start,

and exhaust system components in 2003 and 2005 revealed no significant corrosion,

cracking, or fouling. Eddy current inspections of the control room chiller condensers in

1998 (70RWC-2A) and 2000 (70RWC-2B) revealed no loss of material or fouling of the

condenser tubes. Absence of aging effects proves that the program is effective for

managing aging effects for the control room chiller condensers and EDG components.

In 2002, the control room chillers were the focus of an action plan due to Freon leaks

and reliability problems caused primarily by lack of maintenance personnel with

sufficient knowledge of air conditioning systems and lack of scheduled PM. Corrective

actions improved the scope and schedule of PM and provided training on refrigeration

and air conditioning systems for maintenance personnel.

Preventive maintenance on control room chiller condenser 70RWC-2A in March 2006

revealed corrosion of the carbon steel condenser head inlet/outlet baffle plate and the

inner side of the o-ring groove. A corrective action program work order was issued to

install a new condenser head at the next available opportunity. Eddy current testing of

control room chiller condenser 70RWC-2A in March 2006 revealed several tubes leaking

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at the tube sheet. The tubes are a press fit into the tube sheet. Attempts were made to

roll the tubes tighter into the tube sheet but leakage was still present in most cases. A

corrective action program work order was issued to replace the tubes. In 2000, the

security generator failed its operational test by tripping on high temperature. The cause

was radiator fouling. Corrective actions flushed the cooling system and revised the PM

interval from ten to five years. Confirmation of heat transfer ability and timely corrective

actions prove that the program is effective in managing fouling for the security generator

radiator. Security generator operational testing in 2005 showed the engine coolant

temperature within acceptance criteria after the generator had been running loaded for

20 minutes. These results prove that the program is effective for managing fouling of the

security generator radiator.

The staff reviewed the operating experience for the various systems within the scope of

the PSPM program to confirm that the aging effects identified are consistent with those

in the LRA and with industry operating experience. Also, the staff confirmed that the

corrective actions taken are appropriate for the aging effects identified. The staff

reviewed work orders a sample of work orders and noted that in November 2005,

battery rack inspections noted no signs of corrosion; however, paint was touched up in

areas where acid residue had degraded the paint. This operating experience provides

evidence that the inspections performed as part of the PSPM program are effective at

detecting low-levels of degradation prior to a component loss of intended function

occurring. Repairing the protective paint coating was an appropriate corrective action

since it prevented further degradation from occurring. The staff also reviewed a

condition report and noted that in March 2006, PM on control room chiller condenser

70RWC-2A revealed corrosion of the carbon steel condenser head inlet/outlet baffle

plate, along with the inner side of the o-ring groove. The corrective action taken was to

install a new condenser head at the next available opportunity. This operating

experience provides evidence that the PM activities included in the PSPM program are

also effective at detecting aging degradation. The corrective action taken was

appropriate since the condenser head baffle plate was corroded and was unfit for

continued service. The staff determined that these operating experience events provide

objective evidence that the PSPM program will provide timely detection of aging

degradation and corrective action.

The staff also reviewed plant operating experience reports and confirmed that the

plant-specific operating experience did not include any aging effects for systems and

components within the scope of this program that are not bounded by industry operating

experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable.

Enhancement. In LRA Section B.1.22, the applicant stated an enhancement to their existing

program elements for "scope of program," "parameters monitored/inspected," "detection of

aging effects," and "acceptance criteria." Specifically, the enhancement states:

Prior to the period of extended operation, program activity guidance documents

will be enhanced as necessary to assure that the effects of aging will be

managed such that applicable components will continue to perform their

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intended functions consistent with the current licensing basis for the period of

extended operation.

The staff confirmed by discussion with the applicant that this enhancement is to update

implementing guidance documents, such as plant procedures, and does not alter the technical

elements of the PSPM program. The applicant identified this enhancement as Commitment

No. 13 (JAFP-06-0109, dated July 31, 2007). The staff considers the updating of guidance

documents to be part of program implementation, and not within the scope of the LRA audit.

UFSAR Supplement. In LRA Section A.2.1.24, the applicant provided the UFSAR supplement

for the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the

applicant's license renewal commitment list in LRA Amendment No. 5, Attachment 1,

Revision 1, dated February 1, 2007, and confirmed that the program enhancement is identified

as Commitment No. 13, to be implemented before the period of extended operation. The staff

reviewed this section and determined that the information in the UFSAR supplement provides

an adequate summary description of the program, as required by 10 CFR 54.21(d).

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 theCLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.3.5 Water Chemistry Control - Auxiliary Systems Program

Summary of Technical Information in the Application. LRA Section B.1.29.1 describes the

existing plant-specific Water Chemistry Control - Auxiliary Systems Program.

The Water Chemistry Control - Auxiliary Systems Program manages loss of material for

components exposed to treated water. The program samples, analyzes, and replaces coolant

for the control room and relay room chilled water system, security generator jacket cooling

water, auxiliary boiler heating water, decay heat removal cooling water, and the stator cooling

water system to minimize component exposure to harsh environments.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.1.29.1 regarding the applicant's demonstration of the Water

Chemistry Control - Auxiliary Systems Program to ensure that the effects of aging, as

discussed above, will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation.

During the audit and review, the staff reviewed the Water Chemistry Control - Auxiliary Systems

Program against the AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1,

focusing its review on how the program manages aging effects through the effective

incorporation of 10 elements (i.e., "scope of program," "preventive actions," "parameters

monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance

criteria," "corrective actions," "confirmation process," "administrative controls," and "operating

experience").

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The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are parts of the site-controlled QA program. The staff's evaluation

of the QA program is discussed in SER Section 3.0.4. The remaining seven elements are

discussed below.

(1) Scope of the Program - In LRA Section B.1.29.1, the applicant stated that program

activities include sampling, analysis, and replacement of coolant for the control room

and relay room chilled water system, the security generator jacket cooling water,

auxiliary boiler heating water, decay heat removal cooling water, and the stator cooling

water to minimize component exposure to aggressive environments.

The staff reviewed the program basis document and determined that it adequately

describes the specific systems and components within the scope of this program for

which aging will be managed. The staff reviewed each of these systems and determined

that they use treated water as the cooling medium. Since this program manages aging

by monitoring and analyzing the coolant, these systems are appropriate for inclusion

within the scope of this program.

The staff confirmed that the "scope of program" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.1. The staff concludes that this program element is

acceptable.

(2) Preventive Actions - In LRA Section B.1.29.1, the applicant stated that this program

includes monitoring and control of the control room and relay room chilled water system,

the security generator jacket cooling water, auxiliary boiler heating water, decay heat

removal cooling water, and the stator cooling water to minimize exposure to aggressive

environments.

The staff determined that the program includes monitoring and control of water

chemistry to minimize component exposure to aggressive water environments. The

aging effects managed by this program are loss of material, fouling, and cracking, which

are directly related to the purity and aggressiveness of the water to which the

components are exposed. Therefore, monitoring and controlling the water chemistry is

an effective means of managing aging for the components within the scope of this

program. The staff finds these preventive actions are appropriate to manage the aging

effects for which this program is credited.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff concludes that this program element is

acceptable.

(3) Parameters Monitored or Inspected - In LRA Section B.1.29.1, the applicant stated that

in accordance with industry recommendations, stator cooling water parameters

monitored are conductivity, soluble copper, and dissolved oxygen. In accordance with

industry recommendations, auxiliary boiler heating water parameters monitored are

conductivity, pH, and dissolved oxygen.

The staff noted that this program is credited to manage loss of material, fouling, and

cracking for components exposed to treated water. These aging effects are directly

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related to the purity and aggressiveness of the water, which are based on the

conductivity, pH and dissolved oxygen in the water. Therefore, monitoring these

parameters is an effective means of assessing the purity and aggressiveness of the

water, and determining whether corrective actions are needed to modify the water

chemistry. On this basis, the staff finds these parameters acceptable for this program.

In response to the staff's inquiry on sampling frequency, the applicant stated that stator

cooling water conductivity is monitored weekly, while the dissolved oxygen and soluble

copper are monitored monthly. JAFNPP has two on-line stator cooling water conductivity

monitors. Auxiliary boiler heating water conductivity, pH, and dissolved oxygen are

monitored quarterly. The staff determined that these frequencies are consistent with

industry practice and are acceptable.

In response to the staffs inquiry on the technical basis for selection of parameters to be

=monitored, the applicant stated that Water Chemistry Control - Auxiliary Systems AMP is

based on equipment vendor specifications, chemical vendor recommendations,

technical manuals, industry standards, and operating experience. The staff determined

that the applicant's basis for selection of parameters is acceptable since it considers

vendor specifications, industry standards, and operating experience.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concludes that this

program element is acceptable.

(4) Detection of Aging Effects - In LRA Section B.1.29.1, the applicant stated that the

program manages loss of material for stator cooling water and decay heat removal

cooling water system components, loss of material and fouling for control room and

relay room chilled water system and the security generator jacket cooling water

components, and loss of material and cracking of auxiliary boiler heating water

components. The one-time inspection program describes inspections planned to verify

the effectiveness of water chemistry control programs to ensure that significant

degradation is not occurring and component intended function is maintained during the

period of extended operation.

The staff determined that this program includes monitoring and control of water

chemistry to manage loss of material, fouling, and cracking of auxiliary system

components. These aging effects are directly related to the purity and aggressiveness of

the water; therefore, monitoring these parameters will provide an effective means of

mitigating aging. The monitoring frequencies will provide for timely detection of adverse

water chemistry such that corrective actions can be taken prior to a loss of component

intended function. The staff finds these activities appropriate for managing the aging

effects for which this program is credited since they will provide reasonable assurance

that the component intended function will be maintained for the period of extended

operation.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.4. The staff concludes that this program

element is acceptable.

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(5) Monitoring and Trending - In LRA Section B.1.29.1, the applicant stated that values from

analyses are archived for long-term trending and review.

During the audit and review, the staff asked the applicant for additional information on

the parameters that are to be trended, along with the administrative controls to be used

in implementing a periodic review and determining whether corrective actions are

required.

In response, the applicant stated that the parameters monitored are archived for long

term trending and review. Selection of parameters is as described previously in the

discussion of program element (3) "parameters monitored or inspected." The applicant

further stated that, in accordance with Entergy corporate procedure EN-CY-101,

"Chemistry Activities," Revision 0, the chemistry department trends chemistry and

radiochemistry parameters to allow identification and correction of adverse trends before

limits are exceeded. Data is reviewed as it is generated and adverse data indications

are evaluated. The JAFNPP site chemistry staff reviews the data trends to ensure

adverse trends are noted and addressed in a timely manner. Quarterly group data

review sessions are performed by the site chemistry department to share information on

specific plant chemistry. A corporate chemist periodically participates in the data review

sessions to provide an independent assessment.

The staff reviewed the applicant's procedure and determined that appropriate

administrative controls and program activities are in place to monitor and trend

chemistry parameters to identify aging effects and take corrective actions prior to the

loss of a component intended function. The staff finds that the applicant's use of site

chemistry staff reviews and quarterly group data review sessions is an effective means

of monitoring water chemistry parameters.

The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.5. The staff concludes that this program

element is acceptable.

(6) Acceptance Criteria - In LRA Section B.1.29.1, the applicant stated in accordance with

industry recommendations, acceptance criteria for the stator cooling water system are

as follows.

conductivity < 0.5 pS/cm

dissolved oxygen > 2000 ppb, < 8000 ppb

In accordance with industry recommendations, acceptance criteria for the auxiliary boiler

heating water are as follows:

conductivity <30 pmhos/cm

pH > 5.5, < 10.5

During the audit and review, the staff asked the applicant for additional information on

the acceptance criteria for other auxiliary systems.

In response, the applicant stated that acceptance criteria for the Water Chemistry

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Control - Auxiliary Systems AMP are based on equipment vendor specifications,

chemical vendor recommendations, technical manuals, industry standards, and

operating experience.

The staff reviewed the applicant's water chemistry acceptance criteria and determined

that the criteria for the stator cooling water system and auxiliary boiler heating water are

consistent with acceptance criteria used in the industry. The staff also determined that,

for the other auxiliary systems, the use of vendor recommendations, technical manuals,

industry standards, and operating experience is an acceptable basis for developing

water chemistry acceptance criteria, against which the need for corrective actions can

be evaluated, since it will provide criteria that are consistent with those currently used in

the industry and are proven to be effective in managing aging of these components.

The staff confirmed- that the "acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6. The staff concludes that this program element is

acceptable.

(10) Operating Experience - LRA Section B.1.29.1 states that stator cooling water

conductivity, dissolved oxygen, and copper content sample results from 2000 through

2004 revealed only one instance of a parameter outside acceptance criteria. An

elevated copper reading in September 2000 was determined to be due to rinsing of the

filtration rig with nitric acid. The rig had brass fittings that leeched copper into the

sample. After the brass fittings had been replaced with stainless steel fittings and rinsing

of the rig done with demineralized water, sample results were within acceptance criteria.

Continuous confirmation of stator cooling water quality proves that the program is

effective in managing loss of material for stator cooling water system components.

Hot water boiler conductivity and pH sample results from 2000 through 2004 revealed

no parameter outside the acceptance criteria. Continuous confirmation of hot water

boiler water quality proves that the program is effective in managing loss of material for

auxiliary boiler heating water system components.

During the audit and review, the staff asked the applicant for additional information on

operating, experience for other auxiliary systems.

In response, the applicant stated that the control room and relay room chilled water,

decay heat removal cooling water, and security generator jacket cooling water systems

are not currently monitored; therefore, operating experience providing objective

evidence of program effectiveness does not exist. Industry recommendations and

One-Time Inspection Program results will be considered in determining the parameters

to be monitored, monitoring frequency, and associated acceptance criteria.

The staff reviewed plant operating experience review reports and condition reports and

verified that there were no aging effects identified that are not bounded by industry

operating experience. The staff noted that operating experience discussed in the LRA

includes an instance in which elevated levels of copper were detected, indicating a loss

of material in the stator cooling water system. The cause was determined to be the use

of nitric acid as a rinsing agent in the system, which contacted brass fittings used in the

system resulting in the release of copper from the fittings. Appropriate corrective actions

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were taken to resolve the problem by changing the fitting material and the rinsing agent.

The staff confirmed that the "operating experience" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.10. The staff finds this program element

acceptable.

The staff noted that LRA Section B.1.29.1 states one enhancement to the applicant's

existing Water Chemistry Control-Auxiliary Systems program. However, in program

basis document, the applicant states three enhancements. In its response, the applicant

stated that it will correct the LRA to reflect the three enhancements. In its letter dated

February 1, 2007, the applicant revised LRA Section B.1.29.1 to add these

enhancements.

Enhancement 1.. In the program basis document, JAF-RPT-05-LRD02, Section. 4.22.1,

Revision 4, the applicant stated an enhancement to their existing program element for

"scope of program." The enhancement states the following:

Guidance for sampling and analysis of coolant for the control room and relay

room chilled water, decay heat removal cooling water, and the security generator

jacket cooling water will be added to the Water Chemistry Control - Auxiliary

Systems Program procedures. Industry recommendations and One-Time

Inspection Program results will be considered in determining the parameters to

be sampled and the analytical techniques to be used.

The staff determined that, since this is a plant-specific program, this enhancement is not

to meet the recommendations in the GALL Report. As such, the staff reviewed this

enhancement as it relates to the ability of this program to adequately manage the aging

effects for which it is credited. The staff determined that this enhancement to the "scope

of program" element will add the control room and relay room chilled water, decay heat

removal cooling water, and the security generator jacket cooling water systems to the

scope of the existing Water Chemistry Control - Auxiliary Systems Program. The staff

reviewed these systems and determined that they use treated water similar to the other

systems currently within the scope of this program as the cooling medium; therefore,

including them within the scope of this program is appropriate. The staff finds that

including guidance in the program procedures is necessary to ensure that the program

is properly implemented. On this basis, the staff finds this enhancement acceptable. The

applicant identified this enhancement as Commitment No. 18 (JAFP-06-0109, dated

July 31, 2007).

Enhancement 2. In the program basis document, the applicant stated an enhancement

to their existing program element for "parameters monitored/inspected." The

enhancement stated the following:

Guidance for monitoring to control the concentration of corrosive

impurities (such as chlorides, sulfates, and dissolved oxygen) to mitigate

degradation of structural materials will be developed for control room and

relay room chilled water, decay heat removal cooling water, and the

security generator jacket cooling water and will be added to the Water

Chemistry Control - Auxiliary Systems Program procedures. Industry

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recommendations and One-Time Inspection Program results will be

considered in determining the parameters to be sampled and the

analytical techniques to be used.

The staff determined that, since this is a plant-specific program, the enhancement is not

to meet the recommendations in the GALL Report. As such, the staff reviewed this

enhancement as it relates to the ability of this program to adequately manage the aging

effects for which it is credited. The staff determined that this enhancement to the

"parameters monitored/inspected" program element will develop guidance on which

parameters to monitor for the control room and relay room chilled water, decay heat

removal cooling water, and the security generator jacket cooling water systems. This

guidance will then be added to the program implementing procedures.

In response to the staff's inquiry on the technical basis for selection of parameters to be

monitored, the applicant stated that Water Chemistry Control - Auxiliary Systems AMP is

based on equipment vendor specifications, chemical vendor recommendations,

technical manuals, industry standards, and operating experience. The staff determined

that the applicant's basis for selection of parameters is acceptable since it considers

information from appropriate sources that will provide reasonable assurance that

acceptable parameters will be selected. The staff finds that including guidance in the

program procedures is necessary to ensure that the program is properly implemented.

On this basis, the staff finds this enhancement acceptable. The applicant identified this

enhancement as Commitment No. 18.

Enhancement 3. In the program basis document, the applicant stated an enhancement

to their existing, program element for "acceptance criteria." The enhancement stated the

following:

Industry standards such as EPRI guidelines along with manufacturer's

recommendations will: be used to establish the appropriate acceptance

criteria for control room and relay room chilled water, decay heat removal

cooling water, and the security generator jacket cooling water and will be

added to the Water Chemistry Control - Auxiliary Systems Program

procedures.

The staff determined that, since this is a plant-specific program, the enhancement is not

to meet the recommendations in the GALL Report. As such, the staff reviewed this

enhancement as it relates to the ability of this program to adequately manage the aging

effects for which it is credited. The staff determined that this enhancement to the

"acceptance criteria" program element will develop acceptance criteria for the control

room and relay room chilled water, decay heat removal cooling water, and the security

generator jacket cooling water systems. The acceptance criteria will be based on

industry standards, such as EPRI guidelines and manufacturer's recommendations. The

staff determined that the applicant's basis for selection of acceptance criteria is

acceptable since it considers information from appropriate sources that will provide

reasonable assurance that appropriate acceptance criteria will be selected. The staff

finds that including guidance in the program procedures is necessary to ensure that the

program is properly implemented. On this basis, the staff finds this enhancement

acceptable. The applicant identified this enhancement as Commitment No. 18.

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UFSAR Supplement. In LRA Section A.2.1.32, the applicant provided the UFSAR supplement

for the Water Chemistry Control - Auxiliary Systems Program. The staff reviewed the

applicant's license renewal commitment list in LRA Amendment No. 5, Attachment 1,

Revision 1, dated February 1, 2007, and confirmed that the program enhancements are

identified as Commitment No. 18, to be implemented before the period of extended operation.

The staff reviewed this section and determined that the information in the UFSAR supplement

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Water Chemistry Control -

Auxiliary Systems 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).

3.0.3.3.6 Bolted Cable Connections Program

During the audit and review, the staff asked the applicant a question regarding its lack of the

Bolted Cable Connections Program. In its letter dated February 1, 2007, the applicant amended

the LRA. The applicant submitted LRA Section B.1.31, "Bolted Cable Connections Program, "

and stated that its Bolted Cable Connections Program is a plant-specific AMP and this AMP has

been developed as an alternate to GALL AMP XI.E6. This program will be implemented prior to

the period of extended operation (Commitment No. 24 -JAFP-06-0109, dated

February 1, 2007).

Summary of Technical Information in the Application. Cable connections are used to connect

cable conductors to other cables or electrical devices. Connections associated with cables

within the scope of license renewal are considered for this program. The most common types of

connections used in nuclear power plants are splices (butt or bolted), crimp-type ring lugs,

connectors, and terminal blocks. Most connections involve insulating material and metallic

parts. This program for electrical cable connections (metallic parts) accounts for loosening of

bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration,

chemical contamination, corrosion, and oxidation. This program does not apply to the

high-voltage switchyard connections.

GALL AMP XI.E4, "Metal Enclosed Bus," manages the aging effects for the connections

associated with metal enclosed bus. GALL AMP XI.E4 manages the aging effects from thermal

cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and

oxidation on the metallic parts of metal enclosed bus (MEB) connections. Therefore, MEB

connections are not included in this program.

Circuits exposed to appreciable ohmic or ambient heating during operation may experience

loosening related to repeated cycling of connected loads or cycling of the ambient temperature

environment. Bolted connectors, splices, and terminal blocks may loosen if subjected to

significant thermally induced stress and cycling. The design of these connections will account

for the stresses associated with ohmic heating, thermal cycling, and dissimilar metal

connections. Therefore, these stressors/mechanisms should not be a significant aging issue.

However, confirmation of the lack of aging effects will be required.

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This sampling program provides for one-time inspections that will be completed prior to the

period of extended operation. The factors considered for sample selection are application

(medium and low voltage), circuit loading (high loading), and location (high temperature, high

humidity, vibration, etc.). The technical basis for the sample selection will be documented. If an

unacceptable condition or situation is identified in the selected sample, the corrective action

program will be used to evaluate the condition and determine appropriate corrective action.

None of the connections in this program are subject to the environmental qualification

requirements of 10 CFR 50.49. This plant-specific AMP has been developed as an alternate to

GALL AMP XI.E6, to provide additional assurance that electrical cable connections will perform .their intended function for the period of extended operation.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the revision to LRA

Section B.1.31, "Bolted Cable Connections Program," information included in LRA

Amendment 5, Attachment 2, dated February 1, 2007, to ensure that the effects of aging, as

discussed above, will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation. The audit team

reviewed the applicant's AMP against the AMP elements found in the SRP-LR, Appendix A.1,

Section A.1.2.3 and SRP-LR Table.1-1. The staffs review of each AMP elements is discussed

as follows:

(1) Scope of Program - The "scope of program" program element criterion in SRP-LR

Appendix A.1.2.3.1 requires that the program scope include the specific structures and

components addressed with this program.

The applicant states in LRA Section B. 1.34, for the "scope of program" program

element, that this program applies to Non-EQ connections associated with cables within

the scope of license renewal. This program does not include the high-voltage (>35 kV)

switchyard connections. The connections within the scope of the license renewal are

evaluated for applicability of this program. The criteria for including connections in the

program are that the connection is a bolted connection and is not covered under the EQ

program or an existing PM program.

The staff determined that the specific commodity groups for which the program

manages aging effects are identified (Non-EQ bolted cable connections associated with

cables within the scope of license renewal), which satisfies the criterion defined in

SRP-LR Appendix A. 1.2.3.1. The staff also determined that the exclusion of

high-voltage (>35 kV) switchyard connections, connections covered under EQ program

and the existing PM program, acceptable. Switchyard connections are addressed in

SER Section 3.6.2.2. EQ cable connections are cover under 10 CFR 50.49. Cable

connections under PM program are periodically inspected. On this basis, the staff finds

that the applicant's scope of program acceptable.

The staff confirmed that the "scope of program" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.1. The staff concludes that this program element is

acceptable.

(2) Preventive Actions - The "preventive actions" program element criterion in SRP-LR

Appendix A. 1.2.3.2 is that condition monitoring programs do not rely on preventive

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actions, and thus, preventive actions need not be provided.

The applicant states in LRA Section B.1.33, for the "preventive actions" program

element, that this one-time inspection program is a condition monitoring program;

therefore, no actions are taken as part of this program to prevent or mitigate aging

degradation.

The staff determined that the preventive actions program element satisfies the criterion

defined in SRP-LR Appendix B.1.2.3.2. The staff finds it acceptable because this is a

condition monitoring program and there is no need for preventive actions. On this basis,

the staff finds the applicant's preventive actions acceptable.

(3) Parameter Monitored/Inspected - The "parameter monitored or inspected" program

element criterion in SRP-LR Appendix A.1.2.3.3 are:

The parameter to be monitored or inspected should be identified and

linked to the degradation of the particular structure and component

intended function(s). The parameter monitored or inspected should

detect the presence and extent of aging effects.

The applicant states in LRA Section B.1.34, for the "parameters monitored/inspected"

program element, that this program will focus on the metallic parts of the cable

connections. The one-time inspection verifies that the loosening of bolted connection

due to thermal cycling, ohmic heating, electrical transients, vibration, chemical

contamination, corrosion, and oxidation is not an issue that requires a periodic AMP.

The staff determined that the parameters monitored/inspected program element

satisfies the criterion defined in SRP-LR Appendix A. 1.2.3.3. Loosening (or high

resistance) of bolted cable connections are the potential aging effects due to thermal

cycling, ohmic heating, electrical transients, vibration, chemical contamination,

corrosion, and oxidation. The design of bolted cable connections usually account for the

above stressors. The one-time inspection is to confirm that these stressors are not an

issue that requires a periodic AMP. On this basis, the staff finds that the applicant's

parameters monitored or inspected acceptable.

(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in

SRP-LR Appendix A.1.2.3.4 are:

Provide information that links the parameters to be monitored or

inspected to the aging effects being managed.

Describe when, where, and how program data are collected (i.e., all

aspects of activities to collect data as part of the program)

Link the method for the inspection population and sample size when

sampling is used to inspect a group of SCs. The inspection population

should be based on such aspects of the SCs as a similarity of materials

of construction, fabrication, procurement, design, installation, operating

environment, or aging effects.

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The applicant states in LRA Section B.1.34, the "detection of aging effects" program

element, that a representative sample of electrical connections within the scope of

license renewal are subject to AMR and will be inspected or tested prior to the period of

extended operation to verify there are no aging effects requiring management during the

period of extended operation. The factors considered for sample selection will be

application (medium and low voltage), circuit loading (high load), and location (high

temperature, high humidity, vibration, etc.). The technical basis for the sample selected

is to be documented. Inspection methods may include thermography, contact resistance

.testing, or other appropriate methods based on plant configuration and industry

guidance. The one-time inspection provides additional confirmation to support operating

experience that shows electrical connection have not experienced a high degree of

failures, and that existing installation and maintenance practices are effective.

The staff determined that this program element satisfies the criteria defined in SRP-LR

Appendix A. 1.2.3.4. Thermography is used to detect aging effects of bolted cable

connections due to thermal cycling, ohmic heating, electrical transients, and vibration.

Contact resistance measurement is an appropriate inspection technique to detect high

resistance of bolted cable connections due to chemical contamination, corrosion, and

oxidation. The staff also determined that the proposed one-time inspection is acceptable

because the design of these connections will account for the stresses associated with

the above aging effects and one-time inspection is to confirm that these

stressors/mecha nisms should not be a significant aging issue. On this basis, the staff

finds the applicant's detection of aging effects acceptable.

(5) Monitoring and Trending - The "monitoring and trending" program element criteria in

SRP-LR Appendix A Section A. 1.2.3.5 are:

Monitoring and trending activities should be described, and they should

provide predictability of the extend of degradation and thus effect timely

corrective or mitigative actions.

This program element should describe how the data collected are

evaluated and may also include trending for a forward look. The

parameter or indicator trended should be described.

The applicant states in LRA Section B.1 .34, for the "monitoring and trending" program

element, that in this program, trending actions are not included as part of this program

because this is a one-time inspection.

The staff determined that absence of trending for testing is acceptable since the test is a

one-time inspection and the ability to trend inspection results is limited by the available

data. Furthermore, the staff did not see a need for such activities. On this basis, the

staff finds the applicant's monitoring and trending acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.5. The staff concludes that this program

element is acceptable.

(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR

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Appendix A.1.2.3.6 are:

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 program should include a methodology for analyzing the results

against applicable acceptance criteria.

Qualitative inspections should be performed to same predetermined

criteria as quantitative inspections by personnel in accordance with

ASME Code and through approved site-specific programs.

The applicant states in LRA Section B.1.34, for the "acceptance criteria" program

element, that the acceptance criteria for each inspection/surveillance are defined by the

specific type of inspection or test performed for the specific type of cable connections.

Acceptance criteria ensure that the intended functions of the cable connections can be

maintained consistent with the CLB.

The staff determined that this program element satisfies the criteria defined in SRP-LR

Appendix A. 1.2.3.6. The staff finds it acceptable on the basis that acceptance criteria for

inspection/surveillance are defined by the specific type of inspection or test performed

for the specific type of connection. The applicant will follow current industry standards

which, when implemented, will ensure that the license renewal intended functions of the

cable connections will be maintained consistent with the current licensing basis.

(7) Corrective Action - The adequacy of the applicant's 10 CFR 50, Appendix B program

associated with this program element is addressed in SER Section 3.04.

The staff reviewed the other aspect of this program element to determine whether or not

it satisfies the criteria defined in SRP-LR Appendix A. 1.2.3.7. The staff found the

requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective action.

On this basis, the staff finds the applicant's corrective action acceptable.

(8) Confirmation Process - The adequacy of the applicant's 10 CFR 50, Appendix B

Program associated with this program element is addressed in SER Section 3.04.

The staff reviewed the other aspect of this program to determine whether or not it

satisfies the criteria defined in SRP-LR Appendix A. 1.2.3.8.The staff found the

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative

controls. On this basis, the staff finds the applicant's confirmation process acceptable.

(9) Administrative Controls - The adequacy of the applicant's 10 CFR Part 50, Appendix B

Program associated with this program element is addressed in SER Section 3.04.

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The staff reviewed the other aspect of this program element to determine whether or not

it satisfies the criteria defined in SRP-LR Appendix A. 1.2.3.9. The staff finds the

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative

controls.

(10) Operating Experience - The "operating experience" program element criterion in

SRP-LR Appendix A. 1.2.3.10 that operating experience 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.

The applicant states, in the JAFNPP supplemental LRA, for "operating experience"

program element, that operating experience has shown that loosening of connections

and corrosion of connections could be a problem without proper installation and

maintenance activities. Industry operating experience supports performing this one-time

inspection program in lieu of a periodic testing program. This one-time inspection

program will verify that the installation and maintenance activities are effective. The

Bolted Cable Connections Program is a new program. Plant and industry operating

experience was considered when this program was developed. Industry operating

experience that forms the basis for the program is described in the operating experience

element of the GALL AMP XI.E6 program description. JAFNPP-specific operating is

consistent with the operating experience in the GALL AMP XI.E6 program description.

In search of operating experience to respond to NEI's concerns about the lack of

operating experience to support GALL AMP XI.E6 (NEI's White Paper on GALL

AMP XI.E6, dated September 5, 2006), the staff confirmed that very few operating

experiences related to failed connections due to aging have been identified and these

operating experiences can not support a periodic inspection as currently recommended

in GALL AMP XI.E6. The staff finds that the proposed one-time inspection program will

ensure that either aging of metallic cable connections is not occurring or existing PM

program is effective such that a periodic inspection program is not required.

The staff confirmed that the "operating experience" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.10 and found this program element

acceptable.

UFSAR SugDlement. The applicant provides its UFSAR Supplement for the Bolted Cable

Connections Program in the supplemental LRA, Appendix A.2.1.36, which states that the Bolted

Cable Connections Program will focus on the metallic parts of the cable connections.

The staff reviewed the applicant's license renewal commitment list in LRA Amendment No. 5,

Attachment 1, Revision 1, dated February 1, 2007, and confirmed that this new program is

identified as Commitment No. 24 (JAFP-06-0109, dated February 1, 2007), to be implemented

before the period of extended operation. The staff reviewed this section and determined that

the information in the UFSAR supplement provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Bolted Cable Connections

Program, the staff concludes that the applicant will have a program that the effects of aging will

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be adequately managed so that the intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.4 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

ten elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA

activities of "corrective actions," "confirmation process," and "administrative controls."

BTP RLSB-1 Table A. 1-1, "Elements of an Aging Management Program for License Renewal,"

provides the following description of these program elements:

(7) Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process - The confirmation process should ensure that preventive actions

are adequate and that appropriate corrective actions are completed and effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and

approval process.

BTP IQMB-1, "Quality Assurance for Aging Management Programs," notes that AMP aspects

that affect the quality of safety-related SSCs are subject to the QA requirements of

10 CFR Part 50 Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the

applicant may use the existing 10 CFR Part 50 Appendix B QA program to address the

elements of "corrective actions," "confirmation process," and "administrative controls."

BTP IQMB-1 provides the following guidance on the QA attributes of AMPs:

" Safety-related SCs are subject to 10 CFR Part 50 Appendix B requirements which are

adequate to address all quality-related aspects of an AMP consistent with the CLB of

the facility for the period of extended operation.

* For nonsafety-related SCs that are subject to an AMR, an applicant has an option to

expand the scope of its 10 CFR Part 50 Appendix B program to include these SCs to

address "corrective action," "confirmation process," and "administrative control" for aging

management during the period of extended operation. In this case, the applicant should

document such commitment in the UFSAR supplement in accordance with

10 CFR 54.21(d).

3.0.4.1 Summary of Technical Information in the Application

In LRA Sections A.2.1, "Aging Management Programs and Activities," and 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. A single QA Program is

used which includes the elements of corrective action, confirmation process, and administrative

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controls. Corrective actions, confirmation, and administrative controls are applied in accordance

with the Corrective Action Program regardless of the safety classification of the components.

Specifically, in LRA Sections A.2.1 and B.0.3, respectively, the applicant stated that the QA

Program implements the.requirements of 10 CFR Part 50, Appendix B, and is consistent with

SRP-LR.

LRA Section B.1, "Aging Management Review Results," provided an AMR summary for each

unique component type or commodity group determined to require aging management during

the period of extended operation.

3.0.4.2 Staff Evaluation

Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of

aging on SCs subject to anAMR will be adequately managed so that their intended functions

will be maintained consistent with the CLB for the period of extended operation. SRP-LR,

Branch Technical Position RLSB-1, "Aging Management Review - Generic," describes ten

attributes of an acceptable AMP. Three of these ten attributes are associated with the QA

activities of corrective action, confirmation process, and administrative control. BTP RLSB-1,

Table A. 1-1, "Elements of an Aging Management Program for license Renewal," provides the

following description of these quality attributes:

" Corrective actions, including root cause determination and prevention of recurrence,

should be timely

" The confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective

" Administrative controls should provide a formal review and approval process

SRP-LR, BTP IQMB-1 noted that those aspects of the AMP that affect quality of safety-related

SSCs are subject to the QA requirements of 10 CFR Part 50, Appendix B. Additionally, for

nonsafety-related SCs subject to an AMR, the applicant's existing 10 CFR Part 50, Appendix B

QA program may be used to address the elements of corrective action, confirmation process,

and administrative control. BTP IQMB-1 provides the following guidance with regard to the QA

attributes of AMPs:

Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements

which are adequate to address all quality related aspects of an AMP consistent

with the CLB of the facility for the period of extended operation. For

nonsafety-related SCs that are subject to an AMR for license renewal, an

applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50

program to include these SCs to address corrective action, confirmation process,

and administrative control for aging management during the period of extended

operation. In this case, the applicant should document such a commitment in the

Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d).

The NRC staff reviewed the applicant's AMP described in LRA Appendix A, "Updated Safety

Analysis Report Supplement," and Appendix B, "Aging Management Programs and Activities,"

and the license renewal documents. The purpose of this review was to ensure that the quality

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assurance attributes (corrective action, confirmation process, and administrative controls) were

consistent with the staff's guidance described in SRP-LR Section A.2, "Quality Assurance for

Aging Management Programs (Branch Technical Position IQMB-1)."

Based on the NRC staff's evaluation, the descriptions of the AMPs and their associated quality

attributes provided in LRA Sections A.2.1 and B.0.3 are consistent with the staff's position

regarding quality assurance for aging management. However, the applicant has not sufficiently

described the use of the quality assurance program and its associated attributes (corrective

action, confirmation process, and administrative controls). Specifically, the applicant did not

identify those AMPs which do not credit the JAFNPP 10 CFR Part 50, Appendix B, Quality

Assurance Program, for the corrective action, confirmation process, and administrative control

attributes, or provide a description of the process used in lieu of the JAFNPP QA Program.

In RAI 3.0-1 dated November 22, 2006, the staff requested that the applicant supplement the

LRA to clarify that the same corrective action program will be applied to all AMPs and that this

program meets the requirements of 10 CFR Part 50, Appendix B and to provide a supplement

to the description in LRA Section A.2.1, to clearly indicate the application of the JAFNPP

10 CFR Part 50, Appendix B, QA Program, or an alternative for the corrective action,

confirmation process, and administrative control attributes in each program.

In its response dated December 21, 2006, the applicant further described the application of the

JAFNPP 10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process,

and administrative controls, and provided a revision to the UFSAR supplement. The revision

stated, in part:

The corrective action controls of the Entergy (10 CFR Part 50, Appendix B)

Quality Assurance Program are applicable to all aging management programs

and activities that are required during the period of extended operation.

The staff reviewed the proposed revision to UFSAR Appendix A, and on the basis of providing

this description which clarifies that the same corrective action program will be applied to all

AMPs and that this program meets the requirements of 10 CFR Part 50, Appendix B, the staff

finds the applicant's response to RAI 3.0-1 acceptable. Therefore, the staff's concern described

in RAI 3.0-1 is resolved.

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 Section A.2.1, LRA Sections B.0.3

and B. 1, and the RAI response, are consistent with the staffs 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).

3.1 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 RV,

internals, and reactor coolant system (RCS) components and component groups of the

3-158
following:

" reactor vessel.

" reactor vessel internals

" reactor coolant pressure boundary

3.1.1 Summary of Technical Information in the Application

In LRA Section 3.1, the applicant provided AMR results for the RV, internals, and RCS

components and component groups. In LRA Table 3.1.1, "Summary of Aging Management

Programs for the Reactor Coolant System Evaluated in Chapter IV of NUREG-1801 ," the

applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL

Report for the RV, internals, and RCS components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of 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 RV, internals, and RCS

components, that are 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 confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL AMRs. The

staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are summarized in SER Section 3.1.2.1.

In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.1.2.2. The staffs

audit evaluations are summarized in SER Section 3.1.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

effects listed were appropriate for the combination of materials and environments specified. The

staff's audit evaluations are summarized in SER Section 3.1.2.3. The staffs evaluation of the

technical review is also documented in SER Section 3.1.2.3.

3-159
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the RV, internals, and RCS components.

Table 3.1-1, provided below, includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.1, that are addressed in the GALL

Report.

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

Components in the GALL Report

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.) _

Steel pressure Cumulative fatigue TLAA, evaluated in TLAA Consistent with

vessel support skirt damage accordance with GALL Report, which

and attachment 10 CFR 54.21(c) recommends further

welds evaluation (See

(3.1.1-1) SER

Section 3.1.2.2.1)

Steel; stainless Cumulative fatigue TLAA, evaluated in TLAA Consistent with

steel; steel with damage accordance with GALL Report, which

nickel-alloy or 10 CFR 54.21(c) recommends further

stainless steel and environmental evaluation (See

cladding; effects are to be SER

nickel-alloy reactor addressed for Section 3.1.2.2.1)

vessel components: Class 1

flanges; nozzles; components

penetrations; safe

ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-2)

Steel; stainless Cumulative fatigue TLAA, evaluated in TLAA Consistent with

steel; steel with damage accordance with GALL Report, which

nickel-alloy or 10 CFR 54.21(c) recommends further

stainless steel and environmental evaluation (See

cladding; effects are to be SER

nickel-alloy reactor addressed for Section 3.1.2.2.1)

coolant pressure Class 1

boundary piping, components

piping components,

and piping elements

exposed to reactor

coolant

(3.1.1-3)

3-160
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

. Item No.)

Steel pump and Cumulative fatigue TLAA, evaluated in TLAA Consistent with

valve closure damage accordance with GALL Report, which

bolting 10 CFR 54.21(c) recommends further

(3.1.1-4) check Code limits evaluation (See

for allowable cycles SER

(less than Section 3.1.2.2.1)

7000 cycles) of

thermal stress

range

Stainless steel and Cumulative fatigue :TLAA, evaluated in TLAA Consistent with

nickel alloy reactor damage accordance with GALL Report, which

vessel intemals '10 CFR 54.21(c) recommends further

components evaluation (See

(3.1.1-5) SER

Section 3.1.2.2.1)

Nickel Alloy tubes Cumulative fatigue TLAA, evaluated in Not Applicable Not applicable to

and sleeves in a damage accordance with BWRs (See SER

reactor coolant and 10 CFR 54.21(c) Section 3.1.2.2.1)

secondary

feedwater/steam

environment

(3.1.1-6)

Steel and stainless Cumulative fatigue TLAA, evaluated in Not Applicable Not applicable to

steel reactor damage accordance with BWRs (See SER

coolant pressure 10 CFR 54.21(c) Section 3.1.2.2.1)

boundary closure

bolting, head

closure studs,

support skirts and

attachment welds,

pressurizer relief

tank components,

steam generator

components, piping

and components

external surfaces

and bolting

(3.1.1-7)

3-161
Component Group Aging Effect/, AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel; stainless Cumulative fatigue TLAA, evaluated in Not Applicable Not applicable to

steel; and damage accordance with BWRs

nickel-alloy reactor 10 CFR 54.21(c)

coolant pressure and environmental

boundary piping, effects are to be

piping components, addressed for

piping elements; Class 1

flanges; nozzles components

and safe ends;

pressurizer vessel

shell heads and

welds; heater

sheaths and

sleeves;

penetrations; and

thermal sleeves

(3.1.1-8)

Steel; stainless Cumulative fatigue TLAA, evaluated in Not Applicable Not applicable to

steel; steel with damage accordance with BWRs (See SER

nickel-alloy or 10 CFR 54.21(c) Section 3.1.2.2.1)

stainless steel and environmental

cladding; effects are to be

nickel-alloy reactor addressed for

vessel components: Class 1

flanges; nozzles; components

penetrations;

pressure housings;

safe ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-9)

Steel; stainless Cumulative fatigue TLAA, evaluated in Not Applicable Not applicable to

steel; steel with damage accordance with BWRs (See SER

nickel-alloy or 10 CFR 54.21(c) Section 3.1.2.2.1)

stainless steel and environmental

cladding; effects are to be

nickel-alloy steam addressed for

generator Class 1

components components

(flanges;

penetrations;

nozzles; safe ends,

lower heads and

welds)

(3.1.1-10)

3-162
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel top head Loss of material Water Chemistry Water Chemistry Consistent with

enclosure (without due to general, and One-Time Control-BWR GALL Report, which

cladding) top head pitting and crevice Inspection (B.1.29.2) and recommends further

nozzles (vent, top corrosion One-Time evaluation (See

head spray or Inspection (B.1.21) SER

RCIC, and spare) Section 3.1.2.2.2,

exposed to reactor Item 1)

coolant (3.1.1-11) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Steel steam Loss of material Water Chemistry Not Applicable Not applicable to

generator shell due to general, and One-Time BWRs (See SER

assembly exposed pitting and crevice Inspection Section 3.1.2.2.2,

to secondary corrosion Item ý1)

feedwater and

steam

(3.1.1-12)

Steel and stainless Loss of material Water Chemistry Water Chemistry Not applicable for

steel isolation due to general and One-Time Control-BWR isolation condenser

condenser (steel only), pitting Inspection (B.1.29.2) and components since

components and crevice One-Time JAFNPP does not

exposed to reactor corrosion Inspection (B.1.21) have an isolation

coolant condenser.

(3.1.1-13)

Consistent with

GALL Report, which

recommends further

evaluation, for other

components

crediting this AMR

(See SER

Section 3.1.2.2.2,

Item 2)

Stainless steel, Loss of material Water Chemistry Water Chemistry Consistent with

nickel-alloy, and due to pitting and and One-Time Control-BWR GALL Report, which

steel with crevice corrosion Inspection (B.1.29.2) and recommends further

nickel-alloy or One-Time evaluation (See

stainless steel Inspection (B.1.21) SER

cladding reactor Section 3.1.2.2.2,

vessel flanges, Item 3)

nozzles,

penetrations, safe

ends, vessel shells;

heads and welds

(3.1.1-14)

3-163
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel; Loss of material Water Chemistry Water Chemistry Consistent with

steel with due to pitting and and One-Time Control-BWR GALL Report, which

nickel-alloy or crevice corrosion Inspection (B.1.29.2) and recommends further

stainless steel One-Time evaluation (See

cladding; and Inspection (B.1.21) SER

nickel-alloy reactor Section 3.1.2.2.2,

coolant pressure Item 3)

boundary

components

exposed to reactor

coolant

(3.1.1-15) __ _

Steel steam Loss of material Inservice Not Applicable Not applicable to

generator upper due to general, Inspection (IWB, BWRs (See SER

and lower shell and pitting and crevice IWC, and IWD), Section 3.1.2.2.2,

transition cone corrosion and Water Item 4)

exposed to Chemistry and, for

secondary Westinghouse

feedwater and Model 44 and

steam 51 S/G, if general

(3.1.1-16) and pitting

corrosion of the

shell is known to

exist, additional

inspection

procedures are to

be developed.

Steel (with or Loss of fracture TLAA, evaluated in TLAA Consistent with

without stainless toughness due to accordance with GALL Report, which

steel cladding) neutron irradiation Appendix G of recommends further

reactor vessel embrittlement 10 CFR 50 and evaluation (See

beltline shell, RG 1.99. The SER

nozzles, and welds applicant may Section 3.1.2.2.3,

(3.1.1-17) choose to Item 1)

demonstrate that

the materials of the

nozzles are not

controlling for the

TLAA evaluations.

Steel (with or Loss of fracture Reactor Vessel Reactor Vessel Consistent with

without stainless toughness due to Surveillance Surveillance GALL Report, which

steel cladding) neutron irradiation (B.1.24) recommends further

reactor vessel embrittlement evaluation (See

beltline shell, SER

nozzles, and welds; Section 3.1.2.2.3,

safety injection Item 2)

nozzles

(3.1.1-18)

3-164
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to A plant-specific Water Chemistry Consistent with

nickel alloy top stress corrosion aging management Control-BWR GALL Report, which

head enclosure cracking and program is to be (B.1.29.2) and recommends further

vessel flange leak intergranular stress evaluated. One-Time evaluation (See

detection line corrosion cracking Inspection (B.1.21) SER

(3.1.1-19) Section 3.1.2.2.4,

Item 1)

Stainless steel Cracking due to Inservice Not Applicable Not applicable (See

isolation condenser stress corrosion Inspection (IWB, SER,

components cracking and IWC, and IWD), Sect'on 3.1.2.2.4,

exposed to reactor .intergranular stress Water Chemistry, Item,2)

coolant corrosion cracking and plant-specific

(3.1.1-20) verification program

Reactor vessel shell Crack growth due to TLAA Not Applicable Not applicable to

fabricated of cyclic loading BWRs (See SER

SA508-Cl 2 forgings Section 3.1.2.2.5)

clad with stainless

steel using a

high-heat-input

welding process

(3.1.1-21)

Stainless steel and Loss of fracture FSAR supplement Not Applicable Not applicable to

nickel alloy reactor toughness due to commitment to BWRs (See SER

vessel internals neutron irradiation (1) participate in Section 3.1.2.2.6)

components embrittlement, void industry RVI aging

exposed to reactor swelling programs

coolant and neutron (2) implement

flux applicable results

(3.1.1-22) (3) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel Cracking due to A plant-specific Not Applicable Not applicable to

reactor vessel stress corrosion aging management BWRs (See SER

closure head flange cracking program is to be Section 3.1.2.2.7)

leak detection line evaluated.

and

bottom-mounted

instrument guide

tubes

(3.1.1-23)

3-165
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Class 1 cast Cracking due to Water Chemistry Not Applicable Not applicable to

austenitic stainless stress corrosion and, for CASS BWRs (See SER

steel piping, piping cracking components that do Section 3.1.2.2.7)

components, and not meet the

piping elements NUREG-0313

exposed to reactor guidelines, a

coolant plant-specific aging

(3.1.1-24) management

program

Stainless steel jet Cracking due to A plant-specific Water Chemistry Consistent with

pump sensing line cyclic loading aging management Control-BWR GALL Report, which

(3.1.1-25) program is to be (B.1.29.2) and recommends further

evaluated. One-Time evaluation (See

Inspection (B.1.21) SER

Section 3.1.2.2.8,

Item 1)

Steel and stainless Cracking due to Inservice Not Applicable Not applicable (See

steel isolation cyclic loading Inspection (IWB, SER

condenser IWC, and IWD) and Section 3.1.2.2.8,

components plant-specific Item 2)

exposed to reactor verification program

coolant

(3.1.1-26)

Stainless steel and Loss of preload due FSAR supplement Not Applicable Not applicable

nickel alloy reactor to stress relaxation commitment to to BWRs (See SER

vessel intemals (1) participate in Section 3.1.2.2.9)

screws, bolts, tie industry RVI aging

rods, and programs

hold-down springs (2) implement

(3.1.1-27) applicable results

(3) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Steel steam Loss of material A plant-specific Not Applicable Not applicable to

generator feedwater due to erosion aging management BWRs (See SER

impingement plate program is to be Section 3.1.2.2.10)

and support evaluated.

exposed to

secondary

feedwater

(3.1.1-28)

3-166
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Cracking due to A plant-specific BWR Vessel Consistent with

steam dryers flow-induced aging management Internals (B.1.7), GALL Report, which

exposed to reactor vibration program is to be with GE SIL-644, recommends further

coolant evaluated. R1 evaluation (See

(3.1.1-29) recommendations SER

as included in Section 3.1.2.2.11)

BWRVIP-139

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable to

reactor vessel stress corrosion and FSAR BWRs (See SER

internals cracking, . supplement Section 3.1.2.2.12)

components irradiation-assisted commitment to

(e.g., Upper stress corrosion (1) participate in

internals assembly, cracking industry RVI aging

RCCA guide tube programs

assemblies, (2) implement

Baffle/former applicable results

assembly, Lower (3) submit for NRC

internal assembly, approval > 24

shroud assemblies, months before the

Plenum cover and extended period an

plenum cylinder, RVI inspection plan

Upper grid based on industry

assembly, Control recommendation.

rod guide tube

(CRGT) assembly,

Core support shield

assembly, Core

barrel assembly,

Lower grid

assembly, Flow

distributor

assembly, Thermal

shield,

Instrumentation

support structures)

(3.1.1-30)

Nickel alloy and Cracking due to Inservice Not Applicable Not applicable to

steel with primary water stress Inspection (IWB, BWRs (See SER

nickel-alloy cladding corrosion cracking IWC, and IWD) and Section 3.1.2.2.13)

piping, piping Water Chemistry

component, piping and FSAR supp

elements, commitment to

penetrations, implement

nozzles, safe ends, applicable plant

and welds (other commitments to

than reactor vessel (1) NRC Orders,

head); pressurizer Bulletins, and

heater sheaths, Generic Letters

sleeves, diaphragm associated with

plate, manways and nickel alloys and

flanges; core (2) staff-accepted

support pads/core industry guidelines.

guide lugs

(3.1.1-31)

3-167
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel steam Wall thinning due to A plant-specific Not Applicable Not applicable to

generator feedwater flow-accelerated aging management BWRs (See SER

inlet ring and corrosion program is to be Section 3.1.2.2.14)

supports evaluated.

(3.1.1-32)

Stainlesssteel and Changes in FSAR supplement Not Applicable Not applicable to

nickel alloy reactor dimensions due to commitment to BWRs (See SER

vessel internals void swelling (1) participate in Section 3.1.2.2.15)

components industry RVI aging

(3.1.1-33) programs

(2) implement

applicable results

(3) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel and Cracking due to Inservice Not Applicable Not applicable to

nickel alloy reactor stress corrosion Inspection (IWB, BWRs (See SER

control rod drive cracking and IWC, and IWD) and Section 3.1.2.2.16)

head penetration primary water stress Water Chemistry

pressure housings corrosion cracking and for nickel alloy,

(3.1.1-34) comply with

applicable NRC

Orders and provide

a commitment in

the FSAR

supplement to

implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

industry guidelines.

Steel with stainless Cracking due to Inservice Not Applicable Not applicable to

steel or nickel alloy stress corrosion Inspection (IWB, BWRs (See SER

cladding primary cracking and IWC, and IWD) and Section 3.1.2.2.16)

side components; primary water stress Water Chemistry

steam generator corrosion cracking and for nickel alloy,

upper and lower comply with

heads, tubesheets applicable NRC

and tube-to-tube Orders and provide

sheet welds a commitment in

(3.1.1-35) the FSAR

supplement to

implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

industry guidelines.

3-168
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Nickel alloy, Cracking due to Water Chemistry Not Applicable Not applicable to

stainless steel stress corrosion and One-Time BWRs (See SER

pressurizer spray cracking and Inspection and, for Section 3.1.2.2.16)

head primary water stress nickel alloy welded

(3.1.1-36) corrosion -cracking spray heads,

comply with

applicable NRC

Orders and provide

a commitment in

the FSAR

supplement to

implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

industry guidelines.

Stainless steel and Cracking due to Water Chemistry Not Applicable Not applicable to

nickel alloy reactor stress corrosion and FSAR BWRs (See SER

vessel internals cracking, primary supplement Section 3.1.2.2.17)

components water stress commitment to

(e.g., Upper corrosion cracking, (1) participate in

intemals assembly, irradiation-assisted industry RVI aging

RCCA guide tube stress corrosion programs

assemblies, Lower cracking (2) implement

internal assembly, applicable results

CEA shroud (3) submit for NRC

assemblies, Core approval > 24

shroud assembly, months before the

Core support shield extended period an

assembly, Core RVI inspection plan

barrel assembly, based on industry

Lower grid recommendation.

assembly, Flow

distributor

assembly)

(3.1.1-37)

Steel (with or Cracking due to BWR CR Drive BWR CRD Return Consistent with

without stainless cyclic loading Return Line Nozzle Line Nozzle (B.1.2) GALL Report, which

steel cladding) and Water recommends no

control rod drive Chemistry further evaluation

return line nozzles Control-BWR (See SER

exposed to reactor (B.1.29.2) (as a Section 3.1.2.1)

coolant supplement)

(3.1.1-38)

Steel (with or Cracking due to BWR Feedwater BWR Feedwater Consistent with

without stainless cyclic loading Nozzle Nozzle (B.1.3) GALL Report, which

steel cladding) recommends no

feedwater nozzles further evaluation

exposed to reactor (See SER

coolant Section 3.1.2.1)

(3.1.1-39)

3-169
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to BWR Penetrations Water Chemistry Consistent with

nickel alloy stress corrosion and Water Control-BWR GALL Report, which

penetrations for cracking, Chemistry (B.1.29.2) and recommends no

control rod drive Intergranular stress either the BWR further evaluation

stub tubes corrosion cracking, Penetration (B.1.4), (See SER

instrumentation, jet cyclic loading BWR Vessel Section 3.1.2.1.1)

pump Internals (B.1.7) or

instrumentation, Inservice Inspection

standby liquid (B.1.16.2)

control, flux monitor,

and drain line

exposed to reactor

coolant

(3.1.1-40)

Stainless steel and Cracking due to BWR Stress Water Chemistry Consistent with

nickel alloy piping, stress corrosion Corrosion Cracking Control-BWR GALL Report, which

piping components, cracking and and Water (B.1.29.2) and recommends no

and piping elements intergranular stress Chemistry either the BWR further evaluation

greater than or corrosion cracking Stress Corrosion (See SER

equal to 4 NPS; Cracking (B.1.5), Section 3.1.2.1.2)

nozzle safe ends BWR Feedwater

and associated Nozzle (B.1.3),

welds BWR Vessel

(3.1.1-41) Internals (B.1.7) or

One-Time

Inspection (B.1.21)

Stainless steel and Cracking due to BWR Vessel ID BWR Vessel ID Consistent with

nickel alloy vessel stress corrosion Attachment Welds Attachment Welds GALL Report, which

shell attachment cracking and and Water (B.1.6) and Water recommends no

welds exposed to intergranular stress Chemistry Chemistry further evaluation

reactor coolant corrosion cracking Control-BWR (See SER

(3.1.1-42) (B.1.29.2) Section 3.1.2.1)

Stainless steel fuel Cracking due to BWR Vessel BWR Vessel Consistent with

supports and stress corrosion Intemals and Water Internals (B.1 7) GALL Report, which

control rod drive cracking and Chemistry and Water recommends no

assemblies control intergranular stress Chemistry further evaluation

rod drive housing corrosion cracking Control-BWR (See SER

exposed to reactor (B.1.29.2) Section 3.1.2.1)

coolant

(3.1.1-43)

3-170
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to BWR Vessel BWR Vessel Consistent with

nickel alloy core stress corrosion Internals and Water Intemals (B.1.7) GALL Report, which

shroud, core plate, cracking, Chemistry and Water recommends no

core plate bolts, intergranular stress Chemistry further evaluation

support structure, corrosion cracking, Control-BWR (See SER

top guide, core irradiation-assisted (B.1.29.2) Section 3.1.2.1)

spray lines, stress corrosion

spargers, jet pump cracking

assemblies, control

rod drive housing,

nuclear

instrumentation

guide tubes

(3.1.1-44)

Steel piping, piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with

components, and flow-accelerated Corrosion Corrosion (B.1.14) GALL Report, which

piping elements corrosion recommends no

exposed to reactor further evaluation

coolant (See SER

(3.1.1-45) Section 3.1.2.1)

Nickel alloy core Cracking due to Inservice Not Applicable Not applicable (See

shroud and core stress corrosion Inspection (IWB, SER

plate access hole cracking, IWC, and IWD), Section 3.1.2.1.8)

cover (mechanical intergranular stress and Water

covers) corrosion cracking, Chemistry

(3.1.1-46) irradiation-assisted

stress corrosion

cracking

Stainless steel and Loss of material Inservice Water Chemistry Consistent with

nickel-alloy reactor due to pitting and Inspection (IWB, Control-BWR GALL Report, which

vessel internals crevice corrosion IWC, and IWD), (B.1.29.2), BWR recommends no

exposed to reactor and Water Vessel Internals further evaluation

coolant Chemistry (B.1.7), and (See SER

(3.1.1-47) One-Time Section 3.1.2.1.3)

Inspection (B.1.21)

Steel and stainless ý Cracking due to Inservice Inservice Inspection Consistent with

steel. Class 1 piping, stress corrosion Inspection (IWB, (B.1.16.2), Water GALL Report, which

fittings and branch cracking, IWC, and IWD), Chemistry recommends no

connections intergranular stress Water Chemistry, Control-BWR further evaluation

< NPS 4 exposed to corrosion cracking and One-Time (B.1.29.2), and (See SER

reactor coolant (for stainless steel Inspection of ASME One-Time Section 3.1.2.1.4)

(3.1.1-48) only), and thermal Code Class 1 . Inspection (B.1.21)

and mechanical Small-bore Piping

loading

3-171
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Nickel alloy core Cracking due to Inservice BWR Vessel Consistent with

shroud and core stress corrosion Inspection (IWB, Internals (B.1.7) GALL Report, which

plate access hole cracking, IWC, and IWD), and Water recommends no

cover (welded intergranular stress Water Chemistry, Chemistry Control further evaluation

covers) corrosion cracking, and, for BWRs with -BWR (B.1.29.2) (See SER

(3.1.1-49) irradiation-assisted a crevice in the Section 3.1.2.1.5)

stress corrosion access hole covers,

cracking augmented

inspection using UT

or other

demonstrated

acceptable

inspection of the

access hole cover

welds

High-strength low Cracking due to Reactor Head Reactor Head Consistent with

alloy steel top head stress corrosion Closure Studs Closure Studs GALL Report, which

closure studs and cracking and (B.1.23) recommends no

nuts exposed to air intergranular stress further evaluation

with reactor coolant corrosion cracking (See SER

leakage Section 3.1.2.1)

(3.1.1-50)

Cast austenitic Loss of fracture Thermal Aging and Thermal Aging and Consistent with

stainless steel jet toughness due to Neutron Irradiation Neutron Irradiation GALL Report, which

pump assembly thermal aging and Embrittlement of Embrittlement of recommends no

castings; orificed neutron irradiation CASS CASS (B.1.28) further evaluation

fuel support embrittlement (See SER

(3.1.1-51) Section 3.1.2.1)

Steel and stainless Cracking due to Bolting Integrity Bolting Integrity Consistent with

steel reactor stress corrosion (B.1.30) GALL Report, which

coolant pressure cracking, loss of recommends no

boundary (RCPB) material due to further evaluation

pump and valve wear, loss of (See SER

closure bolting, preload due to Section 3.1.2.1)

manway and thermal effects,

holding bolting, gasket creep, and

flange bolting, and self-loosening

closure bolting in

high-pressure and

high-temperature

systems

(3.1.1-52)

Steel piping, piping Loss of material Closed-Cycle Not Applicable Not applicable (See

components, and due to general, Cooling Water SER

piping elements pitting and crevice System Section 3.1.2.1.8)

exposed to closed corrosion

cycle cooling water

(3.1.1-53)

3-172
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

ItemNo.)

Copper alloy piping, Loss of material Closed-Cycle Not Applicable Not applicable (See

piping components, due to pitting, Cooling Water SER

and piping elements crevice, and System Section 3.1.2.1.8)

exposed to closed galvanic corrosion

cycle cooling water

(3.1.1-54)

Cast austenitic Loss of fracture Inservice Inservice Inspection Consistent with

stainless steel toughness due to inspection (IWB, (B.1.16.2) or GALL Report, which

Class 1 pump thermal aging IWC, and IWD). One-Time recommends no

casings, and valve embrittlement Thermal aging Inspection (B.1.21) further evaluation

bodies and bonnets susceptibility (See'SER

exposed to reactor screening is not Section 3.1.2.1.6)

coolant > 2500C necessary,

(> 4821 F) inservice inspection

(3.1.1-55) requirements are

sufficient for

managing these

aging effects.

ASME Code

Case N-481 also

provides an

alternative for pump

casings.

Copper alloy Loss of material Selective Leaching Not Applicable Not applicable (See

> 15% Zn piping, due to selective of Materials SER

piping components, leaching Section 3.1.2.1.8)

and piping elements

exposed to closed

cycle cooling water

(3.1.1-56)

Cast austenitic Loss of fracture Thermal Aging One-Time Consistent with

stainless steel toughness due to Embrittlement of Inspection (B.1.21) GALL Report, which

Class 1 piping, thermal aging CASS recommends no

piping component, embrittlement further evaluation

and piping elements (See SER

and control rod Section 3.1.2.1.7)

drive pressure

housings exposed

to reactor coolant

> 250 0

C (> 482 0F)

(3.1.1-57)

Steel reactor Loss of material Boric Acid Not Applicable Not applicable to

coolant pressure due to Boric acid Corrosion BWRs

boundary external corrosion

surfaces exposed to

air with borated

water leakage

(3.1.1-58)

3-173
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel steam Wall thinning due to Flow-Accelerated Not Applicable Not applicable to

generator steam flow-accelerated Corrosion BWRs

nozzle and safe corrosion

end, feedwater

nozzle and safe

end, AFW nozzles

and safe ends

exposed to

secondary

feedwater/steam

(3.1.1-59)

Stainless steel flux Loss of material Flux Thimble Tube Not Applicable Not applicable to

thimble tubes (with due to Wear Inspection BWRs

or without chrome

plating)

(3.1.1-60)

Stainless steel, Cracking due to Inservice Not Applicable Not applicable to

steel pressurizer cyclic loading Inspection (IWB, BWRs

integral support IWC, and IWD)

exposed to air with

metal temperature

up to 2880C

(550°F)

(3.1.1-61)

Stainless steel, Cracking due to Inservice Not Applicable Not applicable to

steel with stainless cyclic loading Inspection (IWB, BWRs

steel cladding IWC, and IWD)

reactor coolant

system cold leg, hot

leg, surge line, and

spray line piping

and fittings exposed

to reactor coolant

(3.1.1-62)

Steel reactor vessel Loss of material Inservice Not Applicable Not applicable to

flange, stainless due to Wear Inspection (IWB, BWRs

steel and nickel IWC, and IWD)

alloy reactor vessel

internals exposed to

reactor coolant

(e.g., upper and

lower internals

assembly, CEA

shroud assembly,

core support barrel,

upper grid

assembly, core

support shield

assembly, lower

grid assembly)

(3.1.1-63)

3-174
Component Group Aging Effect/ AMP In GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to Inservice Not Applicable Not applicable to

steel with stainless stress corrosion Inspection (IWB, BWRs

steel or nickel alloy cracking, primary IWC, and IWD) and

cladding pressurizer water stress Water Chemistry

components corrosion cracking

(3.1.1-64)

Nickel alloy reactor Cracking due to Inservice Not Applicable Not applicable to

vessel upper head primary water stress Inspection (IWB, BWRs

and control rod corrosion cracking IWC, and IWD).and

drive penetration Water Chemistry

nozzles, instrument and Nickel-Alloy

*tubes, head vent Penetration Nozzles

pipe (top head), and Welded to the

welds Upper Reactor

(3.1.1-65) Vessel Closure

Heads of

Pressurized Water

Reactors

Steel steam Loss of material Inservice Not Applicable Not applicable to

generator due to erosion Inspection (IWB, BWRs

secondary IWC, and IWD) for

manways and Class 2

handholds components

(cover only)

exposed to air with

leaking

secondary-side

water and/or steam

(3.1.1-66)

Steel with stainless Cracking due to Inservice Not Applicable Not applicable to

steel or nickel alloy cyclic loading Inspection (IWB, BWRs

cladding; or IWC, and IWD),

stainless steel and Water

pressurizer Chemistry

components

exposed to reactor

coolant

(3.1.1-67)

3-175
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel, Cracking due to Inservice Not Applicable Not applicable to

steel with stainless stress corrosion Inspection (IWB, BWRs

steel cladding cracking IWC, and IWD),

Class 1 piping, and Water

fittings, pump Chemistry

casings, valve

bodies, nozzles,

safe ends,

manways, flanges,

CRD housing;

pressurizer heater

sheaths, sleeves,

diaphragm plate;

pressurizer relief

tank components,

reactor coolant

system cold leg, hot

leg, surge line, and

spray line piping

and fittings

(3.1.1-68)

Stainless steel, Cracking due to Inservice Not Applicable Not applicable to

nickel alloy safety stress corrosion Inspection (IWB, BWRs

injection nozzles, cracking, primary IWC, and IWD),

safe ends, and water stress and Water

associated welds corrosion cracking Chemistry

and buttering

exposed to reactor

coolant

(3.1.1-69)

Stainless steel; Cracking due to Inservice Not Applicable Not applicable to

steel with stainless stress corrosion Inspection (IWB, BWRs

steel cladding cracking, thermal IWC, and IWD),

Class 1 piping, and mechanical Water chemistry,

fittings and branch loading and One-Time

connections Inspection of AS ME

< NPS 4 exposed to Code Class 1

reactor coolant Small-bore Piping

(3.1.1-70)

High-strength low Cracking due to Reactor Head Not Applicable Not applicable to

alloy steel closure stress corrosion Closure Studs BWRs

head stud assembly cracking; loss of

exposed to air with material due to

reactor coolant wear

leakage

(3.1.1-71)

Nickel alloy steam Cracking due to Steam Generator Not Applicable Not applicable to

generator tubes and OD stress corrosion Tube Integrity and BWRs

sleeves exposed to cracking and Water Chemistry

secondary intergranular attack,

feedwater/steam loss of material due

(3.1.1-72) to fretting and wear

3-176
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Nickel alloy steam Cracking due to Steam Generator Not Applicable Not applicable to

generator tubes, primary water stress Tube Integrity and BWRs

repair sleeves, and corrosion cracking Water Chemistry

tube plugs exposed

to reactor coolant

(3.1.1-73)

Chrome plated Cracking due to Steam Generator Not Applicable Not applicable to

steel, stainless stress corrosion Tube Integrity and BWRs

* steel, nickel alloy cracking, loss of Water Chemistry

,steam generator material due to

.anti-vibration bars crevice corrosion

exposed to and fretting

secondary

feedwater/steam

(3.1.1-74)

Nickel alloy Denting due to Steam Generator Not Applicable Not applicable to

once-through steam corrosion of carbon Tube Integrity and BWRs

generator tubes steel tube support Water Chemistry

exposed to plate

secondary

feedwater/steam

(3.1.1-75)

Steel steam Loss of material Steam Generator Not Applicable Not applicable to

generator tube due to erosion, Tube Integrity and BWRs

support plate, tube general, pitting, and Water Chemistry

bundle wrapper crevice corrosion,

exposed to ligament cracking

secondary due to corrosion

feedwater/steam

(3.1.1-76)

Nickel alloy steam Loss of material Steam Generator Not Applicable Not applicable to

generator tubes and due to wastage and Tube Integrity and BWRs

sleeves exposed to pitting corrosion Water Chemistry

phosphate

chemistry in

secondary

feedwater/steam

(3.1.1-77)

Steel steam Wall thinning due to Steam Generator Not Applicable Not applicable to

generator tube flow-accelerated Tube Integrity and BWRs

support lattice bars corrosion Water Chemistry

exposed to

secondary

feedwater/steam

(3.1.1-78)

3-177
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Nickel alloy steam Denting due to Steam Generator Not Applicable Not applicable to

generator tubes corrosion of steel Tube Integrity; BWRs

exposed to tube support plate Water Chemistry

secondary and, for plants that

feedwater/steam could experience

(3.1.1-79) denting at the upper

support plates,

evaluate potential

for rapidly

propagating cracks

and then develop

and take corrective

actions consistent

with Bulletin 88-02.

Cast austenitic Loss of fracture Thermal Aging and Not Applicable Not applicable to

stainless steel toughness due to Neutron Irradiation BWRs

reactor vessel thermal aging and Embrittlement of

internals neutron irradiation CASS

(e.g., upper embrittlement

internals assembly,

lower internal

assembly, CEA

shroud assemblies,

control rod guide

tube assembly, core

support shield

assembly, lower

grid assembly)

(3.1.1-80)

Nickel alloy or Cracking due to Water Chemistry Not Applicable Not applicable to

nickel-alloy clad primary water stress BWRs

steam generator corrosion cracking

divider plate

exposed to reactor

coolant

(3.1.1-81)

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable to

steam generator stress corrosion BWRs

primary side divider cracking

plate exposed to

reactor coolant

(3.1.1-82) _ _ I I

3-178
Component Group Aging Effectl AMP in GALL AMP In LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel; Loss of material Water Chemistry Not Applicable Not applicable to

steel with due to pitting and BWRs

nickel-alloy or crevice corrosion

stainless steel

cladding; and

nickel-alloy reactor

vessel internals and

reactor coolant

pressure boundary

components

exposed to reactor

coolant

(3.1.1-83)

Nickel alloy steam Cracking due to Water Chemistry Not Applicable Not applicable to

generator stress corrosion and One-Time BWRs

components such cracking Inspection or

as, secondary side Inservice

nozzles Inspection (IWB,

(vent, drain, and IWC, and IWD).

instrumentation)

exposed to

secondary

feedwater/steam

(3.1.1-84)

Nickel alloy piping, None None None Consistent with

piping components, GALL Report

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.1.1-85)

Stainless steel None None None Consistent with

piping, piping GALL Report

components, and

piping elements

exposed to air -

indoor uncontrolled

(External); air with

borated water

leakage; concrete;

gas

(3.1.1-86)

Steel piping, piping, None None Not Applicable Not applicable (See

components, and SER

piping elements in Section 3.1.2.1.8)

concrete

(3.1.1-87)

The staff's review of the RV, internals, and RCS component groups followed one of several

approaches. One approach, documented in SER Section 3.1.2.1, discusses the staff's review of

the AMR results for components that the applicant indicated are consistent with the GALL

3-179
Report and do not require further evaluation. Another approach, documented in SER

Section 3.1.2.2, discusses the staff's review of the AMR results for components that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.1.2.3, discusses the staff's

review of the AMR results for components that the applicant indicated are not consistent with,

or not addressed in, the GALL Report. The staff's review of AMPs that are credited to manage

or monitor aging effects of the RV, internals, and RCS components is documented in SER

Section 3.0.3.

3.1.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the RV, internals, and RCS components:

" BWR CRD Return Line Nozzle Program

" BWR Feedwater Nozzle Program

" BWR Penetrations Program

" BWR Stress Corrosion Cracking Program

" BWR Vessel ID Attachment Welds Program

" BWR Vessel Internals Program

" External Surfaces Monitoring Program

" Flow-Accelerated Corrosion Program

" Inservice Inspection Program

" One-Time Inspection Program

" Reactor Head Closure Studs Program

" Reactor Vessel Surveillance Program

" Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

(CASS) Program

• Water Chemistry Control - BWR Program

" Water Chemistry Control - Closed Cooling Water Program

" Bolting Integrity Program

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant provided a summary of AMRs for the RV,

internals, and RCS components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report does not

recommend further evaluation, the staff performed an audit and review to determine whether

the plant-specific components contained in these GALL Report component groups were

bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

3-180
Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant is consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the AMP identified by the GALL Report. This note indicates that the

applicant was unable to find a listing of some system components in the GALL Report;

however, the applicant identified a different component in the GALL Report that has the same

material, environment, aging effect, and AMP as the component that was under review. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the AMR line item of the different component was applicable to the

component under review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these

line items to verify consistency with the GALL Report. The staff verified whether the AMR line

item of the different component was applicable to the component under review. The staff

verified whether the identified exceptions to the GALL AMPs had been reviewed and accepted

by the- staff. The staff also determined whether the AMP identified by the applicant was

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the

site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified in the GALL

Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided 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 is discussed below.

3.1.2.1.1 Cracking due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking,

and Cyclic Loading

LRA Table 3.1.1, Item 3.1.1- 40, addresses cracking due to SCC, IGSCC, and cyclic loading for

stainless steel and nickel alloy penetrations for control rod drive stub tubes, instrumentation, jet

3-181
pump instrumentation, standby liquid control, and flux monitor exposed to reactor water. The

applicant has addressed cracking of the RV drain line nozzle penetration, which is low-alloy

steel with stainless steel cladding, along with other low-alloy steel vessel nozzle penetrations

with stainless steel cladding, in.SER Table 3.1.1-41 (See Section 3.1.2.1.2 of this SER). The

LRA credits the Water Chemistry Control-BWR Program, and either the BWR Penetrations

Program for Core AP/SLC nozzle and instrument nozzles, BWR Vessel Internals Program for

CRD stub tubes or Inservice Inspection Program for incore monitor housings to manage this

aging effect. GALL Report recommends AMPs XI.M8, "BWR Penetrations," and XI.M2,"Water

Chemistry," to manage this aging effect. The LRA Table 2 AMR line items (low-alloy steel with

nickel-based alloy cladding CRD stub tubes and stainless steel incore monitor housings) that

reference this Table 1 line item cite Generic Note E, indicating that the AMR lines are consistent

with GALL Report material, environment, and aging effect, but a different aging management

program is credited.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and BWR

Penetrations Program and its evaluations are documented in SER Sections 3.0.3.1.10 and

3.0.3.2.4, respectively. The staff verified that these aging management programs include

activities that are consistent with the recommendations in the GALL AMPs XI.M8 and XI.M2 to

manage cracking due to SCC and IGSCC for stainless steel and nickel-based alloy components

exposed to reactor water. The staff noted that the CRD stub tube penetrations, which are made

out of low-alloy steel with nickel-based alloy cladding, and the stainless steel incore monitor

housing penetrations are not within the scope of the BWR Penetrations Program. The

inspection and flaw evaluation guidelines given in BWRVIP-47A applicable to the vessel lower

plenum components, which includes the CRD housing and stub tubes, are within the scope of

BWR Vessel Internals Program. Therefore, the applicant appropriately did not credit the BWR

Penetrations Program for managing cracking for these two components. The staff determined

that, in LRA Table 3.1.2-1, cracking of the CRD stub tubes is appropriately managed by the

BWR Vessel Internals Program, which incorporates the guidelines of the staff-approved

BWRVIP-47A for the CRD stub tubes. The staff reviewed the JAFNPP BWR Vessel Internals

Program for consistency with GALL Report, along with the applicable BWRVIP documents, and

found that the applicant does not take any exceptions to BWRVIP-47A. Therefore, the staff

finds the BWR Vessel Internals Program acceptable for managing cracking of the CRD stub

tubes.

In addition, the staff noted that cracking for the incore monitor housings is managed by the

Inservice Inspection Program.

During the audit and review, the staff asked the applicant to provide its technical justification for

not using the BWR Vessel Internals Program to manage aging for these components. In its

response, the applicant stated that it will amend the LRA to include the BWR Vessel Internals

Program, in addition to the Inservice Inspection Program, to manage aging of these

components. In its letter dated February 1, 2007, the applicant amended the LRA to include the

BWR Vessel Internals Program, in addition to the Inservice Inspection Program in LRA

Table 3.1.2-2, "Reactor Vessel Internals," to manage aging of these components. The staff's

evaluation of the applicant's BWR Vessel Internals Program and Inservice Inspection Program

are documented in SER Sections 3.0.3.2.7 and 3.0.3.3.3, respectively. The staff determined

that this LRA amendment is acceptable since the BWR Vessel Internals Program includes the

BWRVIP-47A recommendations for the incore housings without exception. The staff also noted

that the applicant's Inservice Inspection Program performs volumetric or surface examination of

3-182
10% of the peripheral CRD housing welds and periodic leak testing of the RV lower head

(including both the CRD stub tubes), and the incore housing.

Based on the above, the staff finds that the BWR Vessel Internals Program, along with the

Inservice Inspection Program and Water Chemistry Control-BWR Program, will provide

adequate assurance that these pressure boundary components will perform their intended

functions during the period of extended operation. On this basis, the staff finds the AMR results

for this line item acceptable.

3.1.2.1.2 Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress Corrosion

Cracking (IGSCC)

LRA Table 3.1.1, Item 3.1.1- 41, addresses cracking due to SCC and IGSCC for stainless steel

and nickel alloy piping, piping components, and pipe elements (nozzle safe ends and

associated welds) greater than or equal to 4 inches NPS exposed to reactor water. The LRA

Table 2 AMR line items that reference this Table 1 line item cite Generic Note E for 14

component types, indicating that the AMR lines are consistent with GALL Report material,

environment, and aging effect, but a different aging management program is credited. The LRA

credits the Water Chemistry Control-BWR Program and the BWR Stress Corrosion Cracking

Program, further supplemented by the Inservice Inspection Program for some components to

manage aging for these components. For other components, to which the BWR Stress

Corrosion Cracking Program is not applicable, the applicant manages this aging effect using

the Water Chemistry Control-BWR Program, and either the BWR Feedwater Nozzle Program,

BWR Vessel Internals Program, One-Time Inspection Program or Inservice Inspection

Program. The GALL Report recommends AMPs XI.M7, "BWR Stress Corrosion Cracking," and

XI.M2, "Water Chemistry," to manage this aging effect.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and BWR Stress

Corrosion Cracking Program and its evaluations are documented in SER Sections 3.0.3.1.10

and 3.0.3.2.5, respectively. The staff verified that these aging management programs include

activities that are consistent with the recommendations in GALL AMPs XI.M7 and XI.M2 to

manage cracking due to SCC and IGSCC for stainless steel and nickel-based alloy components

exposed to reactor water. In addition, the staff reviewed the scope of the BWR Stress Corrosion

Cracking Program and found that this program is applicable to stainless steel RV nozzle safe

ends greater than 4 inches NPS [i.e., core spray, jet pump instrument, and reactor water

recirculation (RWR) inlet and outlet nozzles]; RWR flow elements, pump casings and covers;

and piping, pipe fittings, and valve bodies of the reactor coolant pressure boundary (RCPB) that

are greater than 4 inches NPS. Therefore, the applicant appropriately did not credit the BWR

Stress Corrosion Cracking Program for managing cracking for several RV and RCPB

components that are not within the scope of this program. The staff finds that, for components

addressed by this AMR line item, crediting the Water Chemistry Control-BWR Program

together with the BWR Stress Corrosion Cracking Program is consistent with the

recommendations in the GALL Report, and is acceptable.

The staff noted that, in LRA Table 3.1.2-1, for AMR line items that reference line Item 3.1.1-41,

cracking of the nozzle-to-safe end welds less than 4 inches NPS (i.e., SLC nozzle-to-safe end

weld), safe ends less than 4 inches NPS (i.e., Core Delta P/SLC and instrumentation), and

thermal sleeves for core spray and RWR inlet nozzles is managed by the BWR Vessel Internals

Program, together with the Water Chemistry Control-BWR Program. In addition, cracking of the

3-183
feedwater thermal sleeve is managed by the BWR Feedwater Nozzle Program together with the

Water Chemistry Control-BWR Program. The staff reviewed the applicant's Water Chemistry

Control-BWR Program, BWR Stress Corrosion Cracking Program, BWR Feedwater Nozzle

Program, and BWR Vessel Internals Program, along with applicable BWRVIP/industry

documents and its evaluations are documented in SER Sections 3.0.3.1.10, 3.0.3.2.5, 3.0.3.2.3,

and 3.0.3.3.3, respectively. The staff confirmed that these thermal sleeves are not within the

scope of the BWR Stress Corrosion Cracking Program since they are not part of the

Code-required pressure boundary components, and they are not welded to the safe ends. The

staff determined that these AMPs are consistent with the recommendations in the GALL

Report, and include inspections that are equivalent to those in the BWR Stress Corrosion

Cracking Program for managing cracking due to SCC and IGSCC. Therefore, the staff finds

that these programs, along with the Water Chemistry Control-BWR Program, will provide

adequate assurance that cracking due to SCC and IGSCC for the components addressed by

this AMR will be managed. On this basis, the staff finds that, for the components addressed by

this AMR, crediting the Water Chemistry Control-BWR Program together with either the BWR

Feedwater Nozzle Program or BWR Vessel Internals Program to manage SCC and IGSCC is

acceptable.

The staff also noted that, in LRA Table 3.1.2-1, for AMR line items that reference line

Item 3.1.1-41, cracking of stainless steel flange leakoff nozzles less than 4 inches NPS, and

low-alloy steel components with stainless steel (full or partial) cladding (i.e, vessel shell

components and vessel nozzles, including the drain line nozzle penetration) are managed by

the applicant's Inservice Inspection Program, in accordance with Section XI of the ASME Code.

The staff reviewed the applicant's Inservice Inspection Program, along with the applicable Code

section. The staff determined that this program is consistent with' the recommendations in the

GALL Report, and includes inspections that are described in GALL AMP XI.M7 for managing

cracking due to SCC and IGSCC. The staff determined that the Inservice Inspection Program

will provide adequate assurance that cracking due to SCC and IGSCC for these vessel

components will be managed. On this basis, the staff finds that, for the components addressed

by these AMR line items that reference Table 3.1.1-41, crediting the Water Chemistry

Control-BWR Program together with the Inservice Inspection Program to manage SCC and

IGSCC is acceptable.

In LRA Table 3.1.2-3, for AMRs that reference line Item 3.1.1-41, cracking of CASS main steam

flow restrictors is managed by the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry

Control-BWR Program and One-Time Inspection Program and its evaluations are documented

in SER Sections 3.0.3.1.10, and 3.0.3.1.6, respectively. The staff determined that it includes

inspections using NDE techniques that will be effective for detecting cracking of CASS

components. The staff finds that, since the main steam flow restrictors are not pressure

boundary components, they do not require periodic inservice examinations; therefore, the

One-Time Inspection Program is acceptable to manage cracking due to SCC or IGSCC for

these components. If cracking is detected, appropriate corrective actions will be taken to

mitigate the aging effect. On this basis, the staff finds that, for the components addressed by

these AMR line items, crediting the Water Chemistry Control-BWR Program together with the

One-Time Inspection Program to manage SCC and IGSCC is acceptable.

The staff finds that either the BWR Vessels Internals Program, BWR Feedwater Nozzle

Program, One-Time Inspection Program, or Inservice Inspection Program, along with the Water

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Chemistry Control-BWR Program, will provide adequate assurance that these vessel

components will perform their intended functions during the period of extended operation. On

this basis, the staff finds the AMR results for this line item acceptable.

3.1.2.1.3 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.1.1, Item 3.1.1- 47, addresses loss of material due to pitting and crevice corrosion

for stainless steel and nickel alloy RV internals exposed to reactor water. The LRA credits the

Water Chemistry Control-BWR Program and the One-Time Inspection Program to manage this

aging effect. The GALL Report recommends AMPs XI.M1, "ASME Section XI Inservice

Inspection, Subsections IWB, IWC, and IWD," and XI.M2, "Water Chemistry," to manage this

aging effect. The LRA also states that the Inservice Inspection Program is not applicable to

most RV internal components since they are not part of the pressure boundary. The LRA

Table 2 AMR line items that reference this Table 1 line item (GALL Report, Table IV,

Item B1-15) cite Generic Note E, indicating that the AMR line items are consistent with the

GALL Report material, environment, and aging effect, but a different aging management

program is credited.

The staff noted that, in LRA Table 3.1.2-2, for AMR line items that reference Table 3.1.1, line

Item 47, loss of material in sixteen RV internal components is managed by the Water Chemistry

Control-BWR Program and the One-Time Inspection Program. The staff reviewed the Water

Chemistry Control-BWR and the BWR Vessel Internals Program for consistency with GALL

AMPs XI.M2 and XI.M9, and found that these AMPs are adequate to manage loss of material

due to pitting and crevice corrosion in the vessel internals components addressed by this AMR

line item. The One-Time Inspection Program will verify the effectiveness of the Water

Chemistry Program at stagnant flow locations in crevices present in the vessel internals

components. The staff's evaluation of the applicant's Water Chemistry Control-BWR Program,

One-Time Inspection Program, and BWR Vessel Internals Program are documented in SER

Sections 3.0.3.1.10, 3.0.3.1.6, and 3.0.3.2.7, respectively.

During the audit and review, the staff asked the applicant to clarify why the ASME

Code-required Inservice Inspections that are performed in accordance with Subsection IWB,

Table IWB-2500-1, Category B-N-2, are not credited to manage this aging effect. In its

response, the applicant stated that, although Inservice Inspection is performed, it is not credited

to manage this aging effect due to the location of these components inside the RV. The

applicant further stated that the BWR Vessel Internals Program provides more effective

inspection of these components in accordance with BWRVIP documents. The applicant

committed to amend the LRA to revise all Table 2 line items referencing AMR line Item 3.1.1-47

for vessel internal components to credit the BWR Vessel Internals Program ( GALL AMP XI.M9)

in addition to the'Water Chemistry Control-BWR Program and the One-Time Inspection

Program. In its letter dated February 1, 2007, the applicant amended the LRA to include the

BWR Vessel Internals Program, in addition to the Inservice Inspection Program in LRA

Table 3.1.2-2, "Reactor Vessel Internals," to manage aging of these components. In addition,

the discussion column of LRA Table 3.1.1, line Item 3.1.1-47, the applicant added the following:

JAFNPP performs all the inspections required by the ASME Section XI Inservice

Inspection Program, but this program is not credited for managing loss of

material because it does not specifically inspect many of the RV internals

components. JAFNPP credits the BWR Vessel Internals Program which

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incorporates the requirements of ASME Section XI, the approved BWRVIP

documents, and other approved industry documents such as vendor letters and

NUREGs.

On the basis of its review of AMR results for the line item as described in the preceding

paragraphs and its comparison of the applicant's results to corresponding recommendations in

the GALL Report, the staff finds that the applicant addressed the ARM appropriately as

recommended by the GALL Report.

3.1.2.1.4 Cracking due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking,

and Thermal and Mechanical Loading

LRA Table 3.1.1, Item 3.1.1-48, addresses cracking due to SCC, IGSCC (for stainless steel

only), and thermal and mechanical loading for steel and stainless steel Class 1 piping, fittings

and branch connections less than 4 inches NPS exposed to reactor water. The LRA credits the

Water Chemistry Control-BWR Program, One-Time Inspection Program and the Inservice

Inspection Program to manage this aging effect, with several exceptions. For condensing

chambers, CRD filter housings, and orifices, only the Water Chemistry Control-BWR and

One-time Inspection Programs are credited. For the control rod drive units, only the Water

Chemistry Control-BWR and ISI Programs are credited. The GALL Report recommends AMPs

XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,"XI.M2,

"Water Chemistry,"and XI. M35, "One-Time Inspection of ASME Code Class 1 Small

Bore-Piping," to manage this aging effect. The LRA Table 2 AMR line items that reference this

Tablel line item cite Generic Note E, indicating that the AMR line items are consistent with the

GALL Report material, environment, and aging effect, but a different aging management

program is credited.

The staff noted that, in LRA Table 3.1.2-3, for AMR line items that reference Table 3.1.1,

Item 3.1.1-48, cracking of condenser chambers, CRD filter housings, and orifices are managed

by the Water Chemistry Control-BWR Program and the One-Time Inspection Program. Also,

cracking of the control rod drive unit pressure boundary components are managed by the

Water Chemistry Control-BWR Program and the Inservice Inspection Program.

During the audit and review, the staff asked the applicant to clarify why all three AMPs

recommended in the GALL Report are not credited to manage cracking of these components.

In its response, the applicant committed to amend the LRA to add the Inservice Inspection

Program to the AMRs for components condensing chambers, CRD filter housings and orifices.

In May 17, 2007, the applicant amended LRA Table 3.1.2-3, for AMRs that reference line

Item 3.1.1-48, to add the Inservice Inspection Program to the AMRs for condensing chambers,

CRD filter housings and orifices. The staff finds this LRA amendment acceptable since it will

make these AMRs consistent with the recommendations in the GALL Report.

For the AMR line items addressing the CRD units, the applicant stated that since these

components are not small bore piping, the One-Time Inspection Program does not apply.

Therefore, the Inservice Inspection Program along with the Water Chemistry Control-BWR

Program are adequate to manage cracking. The staff reviewed the applicant's Inservice

Inspection Program and found that this AMP includes periodic inspections that will be effective

for detecting cracking in the CRD units. The staff finds that the applicant's Inservice Inspection

Program along with the Water Chemistry Control-BWR Program, will provide adequate

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assurance that cracking due to SCC, IGSCC, and IASCC will be managed for these

components.

During the audit and review, the staff also asked the applicant to clarify why generic note E is

cited for AMR line items crediting all AMPs recommended by GALL Report. In its response, the

applicant stated that Generic Note E is used since the JAFNPP Inservice Inspection Program is

considered to be a plant-specific program. The staff finds this acceptable since it is

administrative only and does not impact the technical aspects of the aging management

activities.

The staff finds that, for the components piping and pipe elements less than 4 inches NPS,

condensing chambers, CRD filter housings, orifices, and CRD pressure boundary components

addressed by this AMR, the use of the Water Chemistry Control-BWR Program, Inservice

Inspection Program, and One-Time Inspection Program will effectively manage cracking due to

SCC, IGSCC and cracking due to thermal and mechanical loading. On this basis, the staff finds

the AMR results for this line item acceptable.

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 3.1.1-49, addresses cracking due to SCC, IGSCC, and IASCC for nickel

alloy core shroud and core plate access hole cover (welded) exposed to reactor water. The LRA

credits the Water Chemistry Control-BWR Program and the BWR Vessel Internals Program to

manage this aging effect. The GALL Report recommends AMPs XI.M1, "ASME Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD," with augmented inspections for welded

access hole covers containing crevices, and XI.M2, "Water Chemistry," to manage this aging

effect. The LRA Table 2 AMR line items that reference this Table 1 line item cite Generic

Note E, indicating that the AMR line items are consistent with the GALL Report material,

environment, and aging effect, but a different aging management program is credited.

The staff noted that, in LRA Table 3.1.2-2, for AMRs that reference Table 3.1.1, Item 3.1.1-49,

cracking of the welded access hole cover (indicated as manway covers) is managed by the

BWR Vessel Internals Program and Water Chemistry Control-BWR Program. The staff

reviewed the applicant's Water Chemistry Control-BWR Program and BWR Vessel Internals

Program and its evaluations are documented in SER Sections 3.0.3.1.10, and 3.0.3.2.7,

respectively. The applicant's BWR Vessel Internals Program includes implementation of the

BWRVIP-1 5 program. The LRA also states that the welded access hole covers have no crevice

behind the weld at JAFNPP.

During the audit and review, the staff asked the applicant to clarify how the access hole covers

were welded to the core support plate without creating a creviced region behind the weld.

In its response, the applicant provided a diagram showing the access hole cover design for

JAFNPP. The diagram was obtained from BWRVIP-15, Section 10, which states that the

access hole covers applicable to JAFNPP are welded to the shroud support ledge with a full

penetration weld that leaves no crevice behind the weld, as shown in BWRVIP-15, Figure

2.10.2.4. The staff also reviewed BWRVIP-15 including the plant drawings and determined that

the JAFNPP access hole cover does not have a crevice behind the weld. The staff determined

that these AMPs include GALL AMPs XI.M1 and XI.M2 recommendations, and will provide

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adequate assurance that cracking due to SCC, IGSCC, and IASCC for these components will

be managed. On this basis, the staff finds the AMR results for this line item acceptable.

3.1.2.1.6 Loss of Fracture Toughness due to Thermal Aging Embrittlement (Pump Casings and

Valve Bodies)

LRA Table 3.1.1, item 3.1.1-55, addresses loss of fracture toughness due to thermal

embrittlement in CASS Class 1 pump casings, and valve bodies and bonnets exposed to

reactor coolant water greater than 250 °C. The staff determined that, in LRA Table 3.1.2-3, for

the AMR items that reference LRA Table 3.1.1, AMR item 3.1.1-55, loss of fracture toughness

due to thermal aging embrittlement is managed by either the One-Time Inspection Program or

the Inservice Inspection Program. The Table 2 AMR line items in the LRA that reference this

Table 1 line item cite Generic Note E, indicating that the AMR line items are consistent with the

GALL Report material, environment, and aging effect, but a different AMP is credited.

GALL AMR item IV.C1-3 recommends that GALL AMP XI.M1, "ASME Section XI Inservice

Inspection, Subsections IWB, IWC, and IWD," be credited to manage loss of fracture

toughness due to thermal aging embrittlement in Class 1 pipe casings and Class 1 valve bodies

and bonnets made from CASS, independent of pump casing or valve body size. For the AMR

items of the recirculation pump casings and large bore Class 1 valve bodies made from CASS

(i.e., Class 1 valve bodies made from CASS that are greater or equal to 4 inches NPS in

diameter), the applicant credits its Inservice Inspection Program to manage loss of fracture due

to thermal aging embrittlement in the components. The applicant's Inservice Inspection

Program is the AMP in the LRA that corresponds to GALL AMP XI.M1, "ASME Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD." The staff finds these AMR line items to

be acceptable because the applicant is crediting the AMP that corresponds to the AMP

recommended in GALL AMR item IV.C1-3 for aging management of loss of fracture toughness

due to thermal aging embrittlement. The staff evaluates the ability of the Inservice Inspection

Program to manage loss of fracture toughness due the thermal aging embrittlement in SER

Section 3.0.3.3.3.

For the small bore Class 1 valve bodies made from CASS (i.e, Class 1 valve bodies made from

CASS that are less than 4 inches NPS in diameter), the applicant credits the One-Time

Inspection Program to manage loss of fracture toughness due to thermal aging embrittlement.

As previously stated, GALL AMR item IV.C1 -3 recommends that GALL AMP XI.M1, "ASME

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," be credited to manage loss

of fracture toughness due to thermal aging embrittlement in Class 1 valve bodies and bonnets

made from CASS, independent of valve body size. The staff informed the applicant that the

Inservice Inspection Program should be credited to manage loss of fracture toughness in the

small bore Class 1 valve bodies made from CASS (i.e., Class 1 valve bodies made from CASS

that are less than 4 inches NPS in diameter) because this is in conformance with the staffs

position established in GALL AMR item IV.C1-3 and because the criteria in GALL AMP XI.M32,

"One-Time Inspection," do not include any criteria for manage loss of fracture toughness due to

thermal aging embrittlement in CASS components.

By letter dated May 17, 2007 (ML0714301850, Amendment 11), the applicant amended the

applicable AMR item to credit the Inservice Inspection Program as an additional AMP for

managing loss of fracture toughness due to thermal aging embrittlement in the small bore

Class 1 valve bodies made from CASS. This is acceptable because the amendment of the LRA

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addresses the staff s concern and because the amendment of the AMR item is consistent with

the staffs position established in GALL AMR item IV.C1-3. On the basis of this review, the staff

finds the AMR results for this AMR item to be acceptable.

3.1.2.1.7 Loss of Fracture Toughness due to Thermal Aging Embrittlement (Piping and Piping

Components)

LRA Table 3.1. 1,Item 3.1.1-57, addresses loss of fracture toughness due to thermal

embrittlement in CASS Class 1 piping, piping components, and piping elements exposed to

reactor coolant water greater than 250 °C. The LRA credits the One-Time Inspection Program

to manage loss of fracture toughness. GALL Report recommends AMP XI.M12,"Thermal Aging

Embrittlement of Cast Austenitic Stainless Steel," to manage this aging effect. The LRA Table 2

AMR line items that reference thisTable 1 line item cite Generic Note- E, indicating that the

AMR line items are consistent with GALL Report material, environment, and aging effect, but a

different aging management program is credited.

The staff noted that the applicant does not have an AMP equivalent to the Thermal Aging

Embrittlement of Cast Austenitic Stainless Steel (CASS) Program recommended by the GALL

report. This AMP manages loss of fracture toughness in CASS Class 1 piping, piping

components, piping elements and CRD pressure housings exposed to reactor coolant greater

than 2500C. The applicant has no such components within the scope of the license renewal

except the main steam flow restrictors, which are not pressure boundary components and are

not subject to any inservice inspections. The applicant credits the One-Time Inspection

Program to manage loss of fracture toughness in the main steam flow restrictors. The staff

reviewed the JAFNPP One-Time Inspection Program for consistency with GALL AMP XI.M12

and its evaluation is documented in SER Section 3.0.3.1.6. The staff determined that this AMP

includes inspections using NDE methods specified in the GALL AMP X I.M12 that will detect the

presence of cracking, which is symptomatic of a loss of fracture toughness. The staff finds that

the One-Time Inspection Program will provide adequate assurance that these components will

perform their intended functions during the period of extended operation. On this basis, the staff

finds the AMR results for this line item acceptable.

3.1.2.1.8 AMR Results Identified as Not Applicable

In LRA Table 3.1.1, line Items 46, 53, 54, 56, and 87 are identified as "Not Applicable" since the

component/material/environment combination does not exist at JAFNPP. For each of these line

items, the staff reviewed the LRA and the applicant's supporting documents, and confirmed the

applicant's claim that the component/material/ environment combination does not exist at

JAFNPP. On the basis that JAFNPP does not have the component/material/ environment

combination for these Table 1 line items, the staff finds that these AMR line items are not

applicable to JAFNPP.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing the associated aging effects. On the basis of its review,

the staff concludes that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are indeed consistent with the AMRs in the GALL Report. 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

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the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for

the RV, internals, and RCS components. The applicant provided information concerning how it

will manage the following aging effects:

" cumulative fatigue damage

* loss. of material due to general, pitting, and crevice corrosion

• loss of fracture toughness due to neutron irradiation embrittlement

" cracking due to stress corrosion cracking and intergranular stress corrosion cracking

" crack growth due to cyclic loading

" loss of fracture toughness due to neutron irradiation embrittlement and void swelling

• cracking due to stress corrosion cracking

* cracking due to cyclic loading

" loss of preload due to stress relaxation

" loss of material due to erosion

" cracking due to flow-induced vibration

" cracking due to stress corrosion cracking and irradiation-assisted stress corrosion

cracking

" cracking due to primary water stress corrosion cracking

* wall thinning due to flow-accelerated corrosion

" changes in dimensions due to void swelling

" cracking due to stress corrosion cracking and primary water stress corrosion cracking

" cracking due to stress corrosion cracking, primary water stress corrosion cracking, and

irradiation-assisted stress corrosion cracking

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.1.2.2.

The staff's evaluation of the aging effects is discussed in the following sections.

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3.1.2.2.1 Cumulative Fatigue Damage

The staff reviewed LRA Section 3.1.2.2.1 against the SRP-LR Section 3.1.2.2. criteria.

SRP-LR Section 3.1.2.2.1states that Fatigue is a time-limited aging analysis (TLAA) as defined

in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1).

This TLAA is addressed separately in SRP-LR Section 4.3, "Metal Fatigue Analysis."

In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. The evaluation of fatigue for the RV is discussed in LRA Section 4.3.1.1. The RV

internals are not part of the RCPB. Although not mandatory, fatigue analyses were performed

for selected RV internal components (i.e., core shroud tie rod assembly components and jet

pump assembly diffuser adapters). For those internal components analyzed, the evaluation of

fatigue is discussed in LRA Section 4.3.1.2. Cracking, including cracking due-to fatigue, will be

managed by the BWR Vessel Internals Program for other internal components. With the

exception of the main steam line flow restrictors and reactor water recirculating pumps,

evaluation of the fatigue TLAA for the Class 1 portions of the RCPB piping and components,

including those for interconnecting systems is discussed in LRA Section 4.3.1.3. No fatigue

analysis was required for the main steam line flow restrictors or reactor water recirculating

pumps. Cracking, including cracking due to fatigue, will be managed by the One-Time

Inspection Program for the main steam line flow restrictors, and by the Inservice Inspection

Program for the reactor water recirculating pumps.

The staff noted that, in LRA Section 4.3.1.3, the applicant stated that no RCPB piping

components will exceed the as-designed 7000 full-temperature cycles in 60 years of operation,

and the existing stress analyses remain valid for the period of extended operation, in

accordance with 1OCFR54.21 (c)(1)(1). However, in LRA Section 3.1.2.2.1, the applicant has

taken exception to including the main steam line flow restrictors and RWR pumps in the RCPB

components requiring a fatigue TLAA. Also, in LRA Table 3.1.2-3 the staff noted that the

applicant has credited the One-Time Inspection Program for the main steam flow restrictors,

and the Inservice Inspection Program for the recirculation pump for managing cracking due to

fatigue, as well as loss of fracture toughness.

Therefore, during the audit and review, the staff asked the applicant to clarify why exceptions

are taken for these two components in the RCS.

In its response, the applicant stated that the main steam line flow restrictors and reactor water

recirculation pumps were not designed to a Code that required fatigue analysis. Therefore,

cracking due to fatigue will be managed by the same AMPs that manage cracking due to other

mechanisms in accordance with 1OCFR54.21(c)(1)(iii).

The applicant also stated that fatigue-induced aging effects (i.e., damage which would manifest

itself in the initiation of a fatigue induced crack) in the of main steam flow restrictors will be

managed by the One-Time Inspection AMP since these are not pressure boundary components

requiring inservice examinations as recommended in GALL Report. The staff reviewed the

applicant's One-Time Inspection Program and its evaluations are discussed in SER

Section 3.0.3.1.6. The staff determined that these CASS components are susceptible to

cracking due to fatigue and SCC, and loss of fracture toughness, and are important for the safe

operation of the system. Since they are not subject to periodic inservice examinations by the

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ASME Code, a One-Time Inspection is appropriate to determine their condition prior to the

period of extended operation. If cracks induced by fatigue are detected, appropriate corrective

actions will be taken to mitigate the aging effect. On this basis, the staff finds the One-Time

Inspection Program acceptable for managing fatigue-induced aging effects.

The applicant further stated that fatigue-induced aging effects reactor water recirculation pumps

will be managed by the Inservice Inspection Program since these are reactor water pressure

boundary components and are subject to periodic examinations in accordance with the ASME

Code. The pump casing welds are examined in accordance with IWB-2500-1, Category B-L-1,

while the pump casing itself is examined per Category B-L-2. Since the JAFNPP recirculation

pump casings are CASS components and have no welds, the casings are examined for

cracking using Code-recommended NDE techniques for Code Category B-L-2. The staff

determined that the Code-recommended examinations will effectively detect any cracking that

would initiate for fatigue or other aging mechanisms; therefore, they will provide reasonable

assurance that these components will perform their intended functions during the period of

extended operation. Therefore, the staff finds this acceptable.

In LRA Section 3.1.2.2.1, the applicant stated that fatigue analyses were performed for selected

vessel internal components (i.e., core shroud tie rod assemblies and jet pump diffuser

adapters). For those vessel internal components that were not analyzed for fatigue, cracking,

including cracking due to fatigue, will be managed by the BWR Vessel Internals Program. Since

these components serve no pressure boundary function and are not subject to any surface or

volumetric examinations, the vessel internals program will visually inspect them periodically and

will detect the presence of any cracking. The staff's evaluation of BWR Vessel Internals

Program is discussed in SER Section 3.0.3.2.7. The staff finds that these periodic visual

inspections will provide reasonable assurance that these reactor internal components will

perform their intended functions during the period of extended operation. Therefore, the staff

finds this acceptable.

The staff further noted that in LRA Table 3.1.1, line Items 6, 7, 8, 9, and 10 for cumulative

fatigue are identified as "Not Applicable" because JAFNPP is a BWR plant for which the

component/material/ environment combination does not exist.

The staff's review of the TLAAs in LRA Section 4.3 related to metal fatigue of all Class 1

components within the RV, the RV internals, and the RCPB is presented in SER Section 4.3.1.

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the SRP-LR Section 3.1.2.2.2 criteria.

(1) In LRA Section 3.1.2.2.2, Item 1, the applicant addressed loss of material due to

general, pitting, and crevice corrosion in steel components of the reactor pressure

vessel exposed to reactor coolant. The applicant stated that this aging effect is

managed at JAFNPP by the Water Chemistry Control-BWR Program. The effectiveness

of the Water Chemistry Control-BWR Program will be confirmed by the One-Time

Inspection Program through an inspection of a representative sample of components

crediting this program, including areas of stagnant flow.

SRP-LR Section 3.1.2.2.2, Item 1, states that loss of material due to general, pitting,

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and crevice corrosion could occur in BWR steel top head enclosure (without cladding)

top head nozzles (vent, top head spray or reactor core isolation cooling (RCIC), and

spare) exposed to reactor coolant. The existing program relies on control of reactor

water chemistry to mitigate corrosion. However, control of water chemistry does not

preclude loss of material due to pitting and crevice corrosion at locations of stagnant

flow conditions. Therefore, the effectiveness of the chemistry control program should be

verified to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to verify the effectiveness of the chemistry control program. A

one-time inspection of select components at susceptible locations is an acceptable

method to determine whether an aging effect is not occurring or an aging effect is

progressing very slowly such that the component's intended function will be maintained

during the period of extended operation.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry

Control-BWR Program and its evaluations are documented in SER Sections 3.0.3.1.6

and 3.0.3.1.10, respectively. The staff noted that the aging effect is managed by the

applicant's Water Chemistry Control-BWR Program. In addition, the effectiveness of the

water chemistry control program will be verified by the One-Time Inspection Program.

During the audit and review, the staff reviewed the program basis document for the

One-Time Inspection Program and confirmed that NDEs (including VT-1, ultrasonic, and

surface techniques) will be performed on a representative sample by qualified personnel

following procedures that are consistent with ASME Code Section XI and

10 CFR Part 50, Appendix B. In addition, follow-up of unacceptable inspection findings

will include expansion of sample size and locations. Therefore, the staff determined that

loss of material due to general, pitting, and crevice corrosion in these RV components

will be adequately managed by the Water Chemistry Control-BWR and One-Time

Inspection AMPs. On this basis, the staff finds that applicant has met the criteria of

SRP-LR Section 3.1.2.2.2, Item 1, for further evaluation.

(2) In LRA Section 3.1.2.2.2, Item 2, the applicant stated that the paragraph in SRP-LR

Section 3.1.2.2.2 pertains to BWR isolation condenser components. JAFNPP does not

have an isolation condenser; however, loss of material due to general, pitting, and

crevice corrosion in other steel components within the RCPB exposed to reactor coolant

is managed by the Water Chemistry Control-BWR Program. The effectiveness of the

Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection

Program through an inspection of a representative sample of components crediting this

program including areas of stagnant flow.

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice

corrosion could occur in stainless steel BWR isolation condenser components exposed

to reactor coolant. Loss of material due to general, pitting, and crevice corrosion could

occur in steel BWR isolation condenser components. The existing program relies on

control of reactor water chemistry to mitigate corrosion. However, control of water

chemistry does not preclude loss of material due to pitting and crevice corrosion at

locations of stagnant flow conditions. Therefore, the effectiveness of the chemistry

control program should be verified to ensure that corrosion is not occurring. The GALL

Report recommends further evaluation of programs to verify the effectiveness of the

chemistry control program. A one-time inspection of select components at susceptible

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locations is an acceptable method to determine whether an aging effect is not occurring

or an aging effect is progressing very slowly such that the component's intended

function will be maintained during the period of extended operation.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry

Control-BWR Program and its evaluations are documented in SER Sections 3.0.3.1.6

and 3.0.3.1.10, respectively. The staff confirmed that JAFNPP does not have isolation

condensers in the RCS. However, the applicant credits these programs to manage the

loss of material due to general, pitting, and crevice corrosion in other steel components

within the RCPB exposed to reactor coolant. This aging effect is managed by the Water

Chemistry Control-BWR Program. The effectiveness of the water chemistry control

program will be verified by the One-Time Inspection Program. The staff reviewed the

AMR tables in LRA Section 3.1 and found that several steel components (i.e., piping and

pipe fittings, valves, and the CRD accumulators within the RCPB) credit Water

Chemistry Control-BWR and One-time Inspection AMPs for managing loss of material

due to general, pitting, and crevice corrosion. The GALL Report does not have a line

item for this material/environment/aging effect combination, except for the one Table 1

line item associated with the isolation condenser. Since the components addressed by

this further evaluation in the LRA are exposed to reactor water similar to the isolation

condenser, the staff found that these two AMPs are appropriate to manage the above

aging effect associated with other RCPB components within the RCS. On this basis, the

staff finds that applicant has met the criteria of SRP-LR Section 3.1.2.2.2, Item 2, for

further evaluation.

(3) In LRA Section 3.1.2.2.2, Item 3, the applicant addressed loss of material due to

general, pitting, and crevice corrosion in stainless steel, nickel-alloy and steel with

stainless steel or nickel-alloy clad components of the reactor pressure vessel, and loss

of material in stainless steel (including CASS) components of the RCPB exposed to

reactor coolant. The applicant stated that this aging effect is managed by the Water

Chemistry Control-BWR Program. The effectiveness of the Water Chemistry

Control-BWR Program will be confirmed by the One-Time Inspection Program through

an inspection of a representative sample of components crediting this program including

areas of stagnant flow.

SRP-LR Section 3.1.2.2.2, Item 3, states that loss of material due to pitting and crevice

corrosion could occur for stainless steel, nickel alloy, and steel with stainless steel or

nickel alloy cladding flanges, nozzles, penetrations, pressure housings, safe ends, and

vessel shells, heads and welds exposed to reactor coolant. The existing program relies

on control of reactor water chemistry to mitigate corrosion. However, control of water

chemistry does not preclude loss of material due to pitting and crevice corrosion at

locations of stagnant flow conditions. Therefore, the effectiveness of the chemistry

control program should be verified to ensure that corrosion is not occurring. The GALL

Report recommends further evaluation of programs to verify the effectiveness of the

chemistry control program. A one-time inspection of select components at susceptible

locations is an acceptable method to determine whether an aging effect is not occurring

or an aging effect is progressing very slowly such that the component's intended

function will be maintained during the period of extended operation.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry

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Control-BWR Program and its evaluations are documented in SER Sections 3.0.3.1.6

and 3.0.3.1.10, respectively. The staff determined that the applicant's Water Chemistry

Control-BWR Program is consistent with the recommendations in GALL Report, and will

adequately manage loss of material due to pitting and crevice corrosion in stainless

steel, nickel alloy, and steel with stainless steel or nickel alloy cladding flanges, nozzles,

penetrations, pressure housings, safe ends, and vessel shells, heads and welds

exposed to reactor coolant. The staff verified that the applicant's One-Time Inspection

Program will be able to determine whether loss of material due to pitting or crevice

corrosion in stagnant flow locations is progressing such that the component's intended

function will be maintained during the period of extended operation. On this basis, the

staff finds that applicant has met the criteria of SRP-LR Section 3.1.2.2.2, Item 3, for

further evaluation.

(4) The applicant did not address loss of material due to general, pitting, and crevice

corrosion in the steel pressurized water reactor (PWR) steam generator upper and lower

shell and transition cone exposed to secondary feedwater and steam, which is

associated with the further evaluation in SRP-LR Section 3.1.2.2.2,ltem 4, since this

condition is applicable to PWRs only. The staff concluded that this aging effect is not

applicable since JAFNPP is a BWR plant.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.1.2.2.2. For those line items that apply to LRA Section 3.1.2.2.2,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Section 3.1.2.2.3 against the SRP-LR Section 3.1.2.2.3 criteria.

(1) In LRA Section 3.1.2.2.3, Item 1, the applicant stated that neutron irradiation

embrittlement is a TLAA evaluated for the period of extended operation in accordance

with 10 CFR 54.21(c). The evaluation of loss of fracture toughness for the RV beltline

shell and welds is discussed in SER Section 4.2.

SRP-LR Section 3.1.2.2.3, Item 1, states that applicants must evaluate TLAAs in

accordance with 10 CFR 54.21 (c)(1).

SER Section 4.2 documents the staff's review of the applicant's evaluation of this TLAA.

(2) In LRA Section 3.1.2.2.3, Item 2, the applicant stated that the Reactor Vessel

Surveillance Program manages reduction in fracture toughness due to neutron

embrittlement of RV beltline materials. JAFNPP is a participant in the BWRVIP/ISP. This

program monitors changes in the fracture toughness properties of ferritic materials in

the RPV beltline region.

SRP-LR Section 3.1.2.2.3, Item 2, states that loss of fracture toughness due to neutron

irradiation embrittlement could occur in BWR and PWR RV beltline shell, nozzle, and

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welds exposed to reactor coolant and neutron flux. An RV materials surveillance

program monitors neutron irradiation embrittlement of the RV. Reactor vessel

surveillance program is plant-specific, depending on matters such as the composition of

limiting materials, availability of surveillance capsules, and projected fluence levels. In

accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its

proposed withdrawal schedule for approval prior to implementation. Untested capsules

placed in storage must be maintained for future insertion. Thus, further staff evaluation

is required for license renewal. Specific recommendations for an acceptable AMP are

provided in GALL Report Chapter XI, Section M31.

The staff reviewed the applicant's Reactor Vessel Surveillance Program, and results of

the staffs review are documented in SER Section 3.0.3.2.16. This program monitors

neutron irradiation embrittlement of the RV.

Based on the program identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.1.2.2.3. For those line items that apply to LRA Section 3.1.2.2.3,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion

Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the SRP-LR Section 3.1.2.2.4 criteria.

(1) In LRA Section 3.1.2.2.4, Item 1, the applicant stated that the Water Chemistry

Control-BWR Program manages cracking due to SCC and IGSCC in the stainless steel

vessel flange leak detection lines. The One-Time Inspection Program will verify the

effectiveness of the Water Chemistry Control-BWR Program. The One-Time Inspection

Program will include the vessel flange leak off piping when determining an inspection

sample representative of all JAFNPP small bore piping, and includes the use of

volumetric examination for the detection of cracking.

SRP-LR Section 3.1.2.2.4, Item 1, states that cracking due to SCC and IGSCC could

occur in the 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 existing programs may not be capable of mitigating or detecting cracking due

to SCC and IGSCC.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry

Control-BWR Program and its evaluations are documented in SER Sections 3.0.3.1.6

and 3.0.3.1.10, respectively. The staff determined that it will adequately manage the

effects of stress corrosion cracking in the stainless steel vessel flange leak detection

line. Inspections performed by qualified personnel following a variety of NDE methods,

including visual, volumetric, and surface techniques will identify any incipient defects in

this small bore piping. On this basis, the staff finds that applicant has met the criteria of

SRP-LR Section 3.1.2.2.4, Item 1, for further evaluation.

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(2) In LRA Section 3.1.2.2.4, Item 2, the applicant stated that cracking due to SCC and

IGSCC in stainless steel BWR isolation condenser components exposed to reactor

coolant, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.4, is

not applicable since JAFNPP does not have an isolation condenser.

On the basis that JAFNPP has no isolation condenser components, the staff finds this section

not applicable to JAFNPP.

3.1.2.2.5 Crack Growth Due to Cyclic Loading

In LRA Section 3.1.2.2.5, the applicant stated that cracking due to cyclic loading of PWR vessel

shells, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.5, is applicable

to PWRs only.

The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5 and

finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void

Swelling

in LRA Section 3.1.2.2.6, the applicant stated that loss of fracture toughness of PWR reactor

internals, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.6, is

applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6 and

finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.7 Cracking Due to Stress Corrosion Cracking

In LRA Section 3.1.2.2.7, the applicant stated that cracking due to SCC for PWR reactor flange

leak detection lines made out of stainless steel, which is associated with the further evaluation

in SRP-LR Section 3.1.2.2.7.1, and for PWR Class 1 CASS piping, piping components, and

piping elements, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.7.2

are applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.7 against the criteria in SRP-LR Section 3.1.2.2.7 and

finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.8 Cracking Due to Cyclic Loading

The staff reviewed LRA Section 3.1.2.2.8 against the SRP-LR Section 3.1.2.2.8 criteria.

(1) In LRA Section 3.1.2.2.8, Item 1, the applicant stated that the paragraph in SRP-LR

Section 3.1.2.2.8, Item 1,pertains to the jet pump sensing lines inside the RV. The lines

inside the vessel do not form part of the RCS pressure boundary and their failure would

not affect the performance of any functions within the scope of license renewal. At

JAFNPP, these lines have no license renewal intended function and thus are not subject

to an AMR. However, the lines outside the vessel are part of the RCS pressure

boundary and hence are subject to an AMR.

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SRP-LR Section 3.1.2.2.8, Item 1, states that cracking due to cyclic loading could occur

in the stainless steel BWR jet pump sensing lines. The GALL Report recommends that a

plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.

The staff noted the LRA statements that jet pump flow is not a license renewal function

and that the jet pump sensing lines inside the RPV are not parts of the RCPB. On the

basis that the jet pump sensing lines have no license renewal function, the staff

determines that no AMR for the jet pump sensing lines inside the RPV is required.

The staff noted that the applicant credits the Water Chemistry Control -BWR Program,

Inservice Inspection Program, and One-Time Inspection Program as shown in LRA

Table 3.1.1, item 3.1.1-48, for small-bore steel and stainless steel Class 1 piping,

fittings, and branch connections less than 4-inches NPS exposed to reactor coolant.

The staff reviewed the AMPs and the evaluation is documented in SER

Sections 3.0.3.1.10, 3.0.3.3.3, and 3.0.3.1.6, respectively. The staff finds that the aging

effects for the jet pump sensing lines outside the reactor coolant pressure vessel are the

same as for other small-bore stainless steel piping exposed: to reactor coolant, and

aging effects are managed by the AMPs as recommended in the GALL Report. On the

basis, the staff finds this acceptable.

(2) In LRA Section 3.1.2.2.8, Item 2, the applicant stated that cracking due to cyclic loading

in steel and stainless steel BWR isolation condenser components exposed to reactor

coolant, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.8.2, is

not applicable since JAFNPP does not have an isolation condenser.

The staff finds this section not applicable to JAFNPP because the plant has no isolation

condenser components.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.1.2.2.8. For those line items that apply to LRA Section 3.1.2.2.8,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

In LRA Section 3.1.2.2.9, the applicant stated that loss of preload due to stress relaxation of

PWR reactor vessel internals (RVI) components, which is associated with the further evaluation

in SRP-LR Section 3.1.2.2.9, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9 and

finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.10 Loss of Material Due to Erosion

In LRA Section 3.1.2.2.10, the applicant stated that loss of material due to erosion of PWR

steam generator components, which is associated with the further evaluation in SRP-LR

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Section 3.1.2.2.10, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

In LRA Section 3.1.2.2.11, the applicant addressed cracking due to flow-induced vibration in the

stainless steel steam dryers. The applicant stated that this aging effect is managed by the BWR

Vessel Internals Program. JAFNPP will evaluate BWRVIP-139 once it is approved by the staff

and include its appropriate recommendations in the JAFNPP BWR Vessel Internals Program.

SRP-LR Section 3.1.2.11 states that cracking dueto flow induced vibration could occur for

the BWR stainless steel steam dryers exposed to reactor coolant. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that this aging effect is

adequately managed.

The staff reviewed the applicant's BWR Vessel Internals Program and its evaluations are

documented in SER Section 3.0.3.2.7. The staff determined that the BWR Vessel Internals

AMP, with enhancements, performs periodic inspections of stainless steel steam dryers using

UT or enhanced visual (EVT-1)'examinations based on Information Notice 2002-26 and its

supplements. The applicant's letter dated February 1, 2007, states that it has committed to

enhance the BWR Vessel Internals Program to ensure that the effects of aging on the steam

dryer are managed in accordance with the guidelines of BWRVIP-139 as approved by staff and

accepted by the BWRVIP Executive Committee (Commitment No. 22). This provides

reasonable assurance that the steam dryers will be appropriately managed by the BWR Vessel

Internals AMP during the period of extended operation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.1.2.2.11. For those line items that apply to LRA Section 3.1.2.2.11,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress

Corrosion Cracking

In LRA Section 3.1.2.2.12, the applicant stated that cracking due to SCC and IASCC of PWR

RVI components, which is associated with the further evaluation in SRP-LR Section 3.1.2.2.12,

is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.13 Cracking Due to Primary Water Stress Corrosion Cracking

In LRA Section 3.1.2.2.13, the applicant stated that cracking due to primary water SCC of PWR

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components inside the RV, which is associated with the further evaluation in SRP-LR

Section 3.1.2.2.13, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

In LRA Section 3.1.2.2.14, the applicant stated that wall thinning due to flow-accelerated

corrosion of PWR steam generator feedwater inlet ring and supports, which is associated with

the further evaluation in SRP-LR Section 3.1.2.2.14, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.15 Changes in Dimensions Due to Void Swelling

In LRA Section 3.1.2.2.15, the applicant stated that changes in dimensions due to void swelling

of PWR RVI components, which is associated with the further evaluation in SRP-LR

Section 3.1.2.2.15, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion

Cracking

In LRA Section 3.1.2.2.16, the applicant indicated that cracking due to SCC and primary water

SCC of PWR CRD penetration components, which is associated with the further evaluation in

SRP-LR Section 3.1.2.2.16, Item 1, and PWR pressurizer head spray components, which is

associated with the further evaluation in SRP-LR Section 3.1.2.2.16, Item 2, are applicable to

PWRs only.

The staff reviewed LRA Section 3.1.2.2.16 against the criteria in SRP-LR Section 3.1.2.2.16

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

In LRA Section 3.1.2.2.17, the applicant indicated that cracking due to SCC, primary water

SCC, and IASCC of PWR RVI components, which is associated with the further evaluation in

SRP-LR Section 3.1.2.2.17, is applicable to PWRs only.

The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17

and finds this section not applicable because JAFNPP is a BWR plant.

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

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SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for

which the applicant has claimed consistency with the GALL Report and for which the GALL

Report recommends further evaluation, the staff determined that the applicant has adequately

addressed the issues further evaluated. The staff finds that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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

Summary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-3,

the staff reviewed additional details concerning the results of the AMRs for material,

environment, AERM, and AMP combinations that are not consistent with the GALL Report, or

that are not addressed in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information concerning how the

aging effects will be managed. Specifically, note F indicates that the material for the AMR line

item component is not evaluated in the GALL Report. Note G indicates that the environment for

the AMR line item component and material is not evaluated in the GALL Report. Note H

indicates that the aging effect for the AMR line item component, material, and environment

combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified

in the GALL Report for the line item component, material, and environment combination is not

applicable. Note J indicates that neither the component nor the material and environment

combination for the line item is evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

3.1.2.3.1 Reactor Vessel Summary of Aging Management Evaluation - 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.

The staff noted that LRA Table 3.1.2-1 includes an AMR line item to address cracking of the

CRD return line nozzle cap in the RV system. The cap material used for this component is

Inconel 600. The AMR line item cites Generic Note F, which indicates that this material is not in

the GALL Report for this component. The applicant has credited the BWR CRD Return Line

Nozzle and Water Chemistry Control-BWR Programs to manage cracking due to SCC and

IGSCC. The staff reviewed the Water Chemistry Control-BWR Program and confirmed that it

includes activities to maintain an acceptable level of water purity in the CRD return line nozzle,

which will minimize the susceptibility of this component to cracking. In addition, the staff

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reviewed the BWR CRD Return Line Nozzle Program and confirmed that periodic volumetric

examination of this nozzle cap weld to the low-alloy steel nozzle will provide timely detection of

any degradation of this component. Thus, the structural and pressure boundary integrity of the

RPV will be maintained during the period of extended operation. On this basis, the staff finds

the AMR results for this line item acceptable.

The staff noted that LRA Table 3.1.2-1 includes several AMR line items to address low-alloy

steel or carbon steel external surfaces of vessel components in the RV system exposed to

air-indoor (external). The AMR results state that there are no aging mechanisms or effects for

these material/environment combinations, since these surfaces are at high temperature (above

200 'C) thus precluding any moisture accumulation that could result in corrosion. The AMR line

items cite Generic Note G, which indicates that the environment is not addressed in the GALL

Report for this component and material combination. The staff noted that the low-alloy steel or

carbon steel external surfaces of vessel components (i.e., CRD stub tubes, nozzles, nozzle

flanges, nozzle safe ends, RV bottom head, RV shell, RV upper head) are exposed to a high

normal operating temperature preventing any moisture accumulation that could result in

corrosion. On the basis that the component's high surface temperature precludes the corrosion

of low-alloy steel, the staff concludes that there are no applicable AERMs for these components

exposed to an to air-indoor (external) environment.

The staff noted that LRA Table 3.1.2-1 includes an AMR line item to address loss of material of

low-alloy steel RV external attachments (Le., stabilizer brackets and support skirt) in the RV

system exposed to controlled air-indoor (external). The AMR line item credits the Inservice

Inspection Program to manage this aging effect. The AMR line item cites Generic Note H,

which indicates that this aging effect is not addressed in the GALL Report for this component,

material and environment combination. The staff reviewed the applicant's Inservice Inspection

Program and its evaluations are documented in SER Section 3.0.3.3.3. The staff confirmed that

it includes activities that are adequate to detect any corrosion on the external surface of these

components.

During the audit and review, the staff asked the applicant to discuss the specific activities that

will be performed to manage this aging effect. In its response, the applicant stated that surface

examination using NDE techniques specified in ASME Code Section Xl, Subsection IWB,

Table IWB-2500-1, Category B-K will be used with a sample size of 100% each 10-year

inservice interval. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.1.2-1 includes an AMR line item to address loss of material of

high-strength low-alloy steel vessel flange closure studs, nuts, washers and bushings in the RV

system exposed to controlled air-indoor (external). The AMR line item credits the Reactor Head

Closure Stud Program to manage this aging effect. The AMR line item cites Generic Note H,

which indicates that this aging effect is not addressed in the GALL Report for this component,

material and environment combination. The staff reviewed the applicant's Reactor Head

Closure Stud Program and its evaluations are documented in SER Section 3.0.3.2.15. The RV

Closure Studs Program is listed GALL Report Section XI.M3 as a valid AMP for managing

age-related effects in RV closure studs, nuts, washers and bushings. The staff confirmed that

the applicant's Reactor Head Closure Stud Program includes activities that are adequate to

detect any corrosion of stud external surface or flange. On this basis, the staff finds the AMR

results for this line item acceptable.

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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended .function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.2 Reactor Vessel Internals Summary of Aging Management Evaluation -

LRA Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the

RVI component groups.

The staff noted that LRA Table 3.1.2-2 includes an AMR line item to address loss of preload of

core support rim bolts in the RVI system as a TLAA. The AMR line item cites Generic Note H,

which indicates that this aging effect is not in the GALL Report for this component, material and

environment combination.

The staff reviewed Note H and evaluated the aging effect due to IGSCC in the core plate

hold-down bolts that are listed in LRA Table 3.1.2-2 against the criteria in SRP-LR

Section 3.1.2.2. The staff's evaluation is addressed in the following sections.

The applicant implemented the BWR Vessel Internals Program for managing the aging effects

due to loss of preload and cracking in these bolts. The BWR Vessel Internals Program in turn

invokes the inspection guidelines that are specified in the BWRVIP-25 Report, "BWR Core

Plate Inspection and Flaw Evaluation Guidelines." BWRVIP-25 Report Table 3.1.2-2

recommends that if wedges are not-installed, the core support rim bolts should be inspected for

cracks using enhanced visual testing (EVT-1) from below the core plate or UT from above the

core plate if an effective UT technique is developed.

Since wedges are not currently installed at JAFNPP, the staff requested in RAI 3.1.2-2B dated

January 12, 2007, that the applicant provide information regarding the type of inspection

methods, inspection frequency and the results of the inspections that have been performed

thus far on core support rim bolts.

In its response dated February 12, 2007, .the applicant revised LRA Tables 2.3.1-2 and 3.1.2-2

to use the phrase "core plate hold-down bolts" in lieu of "core support rim bolts" to maintain

consistency in nomenclature.

GALL Report, Volume 2, Revision 1, Item IV.B1-6, recommends GALL AMPs XI.M2, "Water

Chemistry," and XI.M9, "BWR Vessel Internals," for monitoring the aging effect due to IGSCC in

core plate hold-down bolts. Consistent with these requirements, the applicant proposed to

implement the Water Chemistry Control-BWR Program and the BWR Vessel Internals Program

for monitoring the aging degradation of the stainless steel core plate hold-down bolts at

JAFNPP.

The Water Chemistry Control-BWR Program provides adequate control of reactor coolant

system (RCS) water chemistry. The BWR Vessel Internals Program invokes the inspection

requirements specified in the American Society of Mechanical Engineers (ASME) Code

Section XI, Inservice Inspection Program, which mandates implementation of periodic

3-203
inspections and inspection methods for certain reactor vessel internals components. In addition,

the core plate hold-down bolts are inspected per the BWRVIP-25 Report, "BWR Core Plate

Inspection and Flaw Evaluation Guidelines," which requires inspections which are

complimentary to the ASME Code ISI. In the BWR Vessel Internals Program, the applicant

stated that it will inspect the core plate hold-down bolts per the applicable BWRVIP inspection

guidelines for the current inspection period in lieu of the ASME Code ISI requirements after

obtaining staff's approval. If the applicant decides to implement the relevant BWRVIP

inspection guidelines in lieu of the ASME Code ISI requirements for monitoring the aging

degradation of the reactor vessel internals components during the license renewal period, it

must obtain NRC's approval under the provisions of 10 CFR 50.55a.

In RAI 3.1.2-2A dated January 12, 2007, the staff also requested that if the applicant does not

plan to install seismic wedges, it should provide information regarding the accessibility for

performing the inspections, type of inspections including UT technique, and inspection

frequency that will be used to monitor the aging degradation in the core plate hold-down bolts

during the license renewal period.

In its response dated February 12, 2007, to the staff's RAI 3.1.2-2A, the applicant states:

During RO11 in December 1994, twenty core plate hold-down bolts were

examined by visual inspection (VT-1). The bolts were examined from the top side

of the core plate. All examined bolts showed that the weld keeper used as a nut

lock remained fillet welded to the top of the bolt. The pertinent plant drawing

shows that this is typical for all 72 bolt locations.

During R013 in October-November 1998, all 72 core plate hold-down bolts were

examined by visual inspection (VT-3) from the top side of the core plate. This

inspection again showed the nut lock welded to the top of each bolt.

As described in the response to RAI 4.7.3.2-1 below, JAFNPP will perform one

of the following.

1. Install core plate wedges prior to the period of extended operation, or

2. Complete a plant-specific analysis to determine acceptance criteria for

continued inspection of core plate rim hold down bolting in accordance with

BWRVIP-25 and submit the inspection plan to the NRC two years prior to the

period of extended operation for NRC review and approval, or

3. Perform inspection of core plate rim hold down bolts in accordance with ASME

Code Section Xl or in accordance with an NRC-approved version of BWRVIP-25.

If Option 2 is selected, the analysis to determine acceptance criteria will address

the information requested in RAls 3.1.2-2A and 4.7.3.2-1.

License renewal commitment 23 (JAFP-07-0021 letter dated 02/12/2007)

specifies this commitment.

With regards to RAI 3.1.2-2A, the staff finds the applicant's response acceptable. Therefore,

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the staff's concern described in RAI 3.1.2-2A is resolved.

The staff also noted that BWRVIP-25 Report Table 3-2 addresses inspection strategy for the

core plate hold-down bolts. However, in LRA Table 3.1.2-2, the applicant identifies them as

core support rim bolts.

In RAI 3.1.2-2B dated January 12, 2007, the staff requested that the applicant revise LRA

Table 3.1.2-2 to include core plate hold-down bolts in lieu of core support rim bolts to maintain

consistency in nomenclature.

In its response dated 02/12/2007, to RAI 3.1.2-2B, the applicant proposed to revise LRA

Tables 2.3.1-2 and 3.1.2-2 for consistent use of the term "core plate hold-down bolts." The staff

found this editorial change acceptable. Therefore, the-staffs concern described in RAI 3.1.2-2B

is resolved.

Consistent with the requirements specified in GALL Report Table IV.B1-15, in LRA

Table 3.1.2-2 the applicant stated that loss of material due to corrosion of the core plate

hold-down bolts would be monitored by implementing the Water Chemistry Control-BWR

Program. In addition, the applicant stated that an augmented one-time inspection program,

which is not a GALL requirement, will be implemented to verify the effectiveness of the Water

Chemistry Control-BWR Program. Since the applicant complied with the requirements specified

in GALL Report Table IV.B1-15, the staff found that loss of material in the core plate hold-down

bolts due to corrosion is adequately managed by the Water Chemistry Control-BWR Program

and the augmented One-Time Inspection Program. The staff, however, reiterates that the

applicant shall conform to any conditions that are imposed in the section of the SE related to

the Water Chemistry Control-BWR Program.

The staff reviewed LRA Table 3.1.2-2 which addressed loss of preload as an aging effect in the

core plate hold-down bolts and the staff's review is stated below.

The core plate hold-down bolts are subject to stress relaxation due to thermal and irradiation

effects and, consequently, they would experience five to nineteen percent loss of preload. The

applicant identified that loss of preload in core plate hold-down bolts is a TLAA issue. The

applicant, in LRA Section 4.7.3.2 stated that it would comply with the guidelines specified in the

BWRVIP-25 Report which includes inspection criteria for the core plate hold-down bolts. The

applicant also stated that it would either install seismic wedges or perform a plant-specific

analysis that meets the requirements of the BWRVIP-25 Report. If the applicant chooses to

install seismic wedges, the core plate hold-down bolts are excluded from the BWRVIP-25

inspection guidelines. On this basis, the staff finds the AMR results for this line item acceptable.

Details of the staff's review related to this TLAA issue are addressed in SER Section 4.7.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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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3.1.2.3.3 Reactor Coolant Pressure Boundary Summary of Aging Management Evaluation -

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 system component groups, and determined that the applicant did not include any AMR

results with Generic Notes F through J involving material, environment, AERMs and AMP

combinations that are not evaluated in the GALL Report.

Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated

the AMR results involving material, environment, AERMs, and AMP combinations not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the RV, internals, and RCS components, that are within the scope of

license renewal and subject to an AMR, will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.2 Aging Management of Engineered Safety Features 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 the following:

" residual heat removal (RHR)

* core spray

" automatic depressurization (ADS)

" high pressure coolant injection (HPCI)

* reactor core isolation cooling (RCIC)

" standby gas treatment (SGT)

" primary containment penetrations (PCP)

3.2.1 Summary of Technical Information in the Application

In LRA Section 3.2, the applicant provided AMR results for the engineered safety features

systems components and component groups. In LRA Table 3.2.1, "Summary of Aging

Management Programs for Engineered Safety Features Evaluated in Chapter V of

NUREG-1801," the applicant provided a summary comparison of its AMRs with the AMRs

evaluated in the GALL Report for the engineered safety features systems components and

component groups.

In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant provided a summary of the AMR results for

component types associated with (1) RHR system, (2) core spray system, (3) ADS, (4) HPCI

system, (5) RCIC system, (6) SGT system, and (7) PCP.

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In LRA Tables 3.3.2-14-1 through 3.3.2-14-4, 3.3.2-14-7, 3.3.2-14-8, 3.3.2-14-10, and

3.3.2-14-14, the applicant provided results for component types associated with the engineered

safety features (ESFs).

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the engineered safety features systems

components, that are 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 confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are summarized in SER Section 3.2.2.1.

In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.2.2.2. The staffs

audit evaluations are summarized in SER Section 3.2.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

effects listed were appropriate for the combination of materials and environments specified. The

staff's audit evaluations are summarized in SER Section 3.2.2.3. The staff's evaluation of the

technical review is also documented in SER Section 3.2.2.3.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the engineered safety features systems components.

Table 3.2-1, provided below, includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.2, that are addressed in the GALL

Report.

3-207
Table 3.2-1 Staff

GALL Report

Evaluation for Engineered Safety Features Systems Components in the

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel and stainless Cumulative fatigue TLAA, evaluated in TLAA Consistent with

steel piping, piping damage accordance with GALL Report, which

components, and 10 CFR 54.21(c) recommends further

piping elements in evaluation (See

emergency core SER

cooling system Section 3.2.2.2.1)

(3.2.1-1)

Steel with stainless Loss of material A plant-specific Not Applicable Not applicable to

steel cladding pump due to cladding aging management BWRs (See SER

casing exposed to breach program is to be Section 3.2.2.2.2)

treated borated evaluated.

water

(3.2.1-2) Reference NRC

Information

Notice 94-63,

"Boric Acid

Corrosion of

Charging Pump

Casings Caused by

Cladding Cracks"

Stainless steel Loss of material Water Chemistry Water Chemistry Consistent with

containment due to pitting and and One-Time Control - BWR GALL Report which

isolation piping and crevice corrosion Inspection (B.1.29.2), and recommends further

components One-Time evaluation (See

internal surfaces Inspection (B.1.21) SER

exposed to treated Section 3.2.2.2.3,

water Item 1)

(3.2.1-3)

Stainless steel Loss of material A plant-specific Buried Piping and Consistent with

piping, piping due to pitting and aging management Tanks Inspection GALL which

components, and crevice corrosion program is to be (B.1.1) recommends further

piping elements evaluated, evaluation (See

exposed to soil SER

(3.2.1-4) Section 3.2.2.2.3,

Item 2)

Stainless steel and Loss of material Water Chemistry Water Chemistry Consistent with

aluminum piping, due to pitting and and One-Time Control - BWR GALL Report which

piping components, crevice corrosion Inspection (B.1.29.2) and recommends further

and piping elements One-Time evaluation (See

exposed to treated Inspection (B.1.21) SER

water Section 3.2.2.2.3,

(3.2.1-5) Item 3)

3-208
Component Group Aging Effect/ AMP In GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Loss of material Lubricating Oil Oil Analysis Consistent with

copper alloy piping, due to pitting and Analysis and Program (B.1.20) GALL Report which

piping components, crevice corrosion One-Time and One-Time recommends further

and piping elements Inspection Inspection (B.1.21) evaluation(See SER

exposed to Section 3.2.2.2.3,

lubricating oil Item 4)

(3.2.1-6)

Partially encased Loss of material A plant-specific None Not applicable(See

stainless steel tanks due to pitting and aging management SER

with breached crevice corrosion program is to be Section 3.2.2.2.3,

moisture barrier evaluated for pitting ltem•5)

exposed to raw and crevice

water corrosion of tank

(3.2.1-7) bottoms because

moisture and water

can egress under

the tank due to

cracking of the

perimeter seal from

weathering.

Stainless steel Loss of material A plant-specific One-time inspection Consistent with

piping, piping due to pitting and aging management (B.1.21) GALL which

components, piping crevice corrosion program is to be recommends further

elements, and tank evaluated, evaluation (See

internal surfaces SER

exposed to Section 3.2.2.2.3,

condensation Item 6)

(internal)

(3.2.1-8)

Steel, stainless Reduction of heat Lubricating Oil Oil Analysis Consistent with

steel, and copper transfer due to Analysis and Program (B.1.20) GALL Report which

alloy heat fouling One-Time and One-Time recommends further

exchanger tubes Inspection Inspection (B.1.21) evaluation (See

exposed to SER

lubricating oil Section 3.2.2.2.4,

(3.2.1-9) Item 1)

Stainless steel heat Reduction of heat Water Chemistry Water Chemistry Consistent with

exchanger tubes transfer due to and One-Time Control-BWR GALL Report which

exposed to treated• fouling Inspection (B.1.29.2) and recommends further

water One-Time evaluation (See

(3.2.1-10) Inspection (B.1.21) SER

Section 3.2.2.2.4,

Item 2)

Elastomer seals Hardening and loss A plant-specific None Not applicable (See

and components in of strength due to aging management SER

standby gas elastomer program is to be Section 3.2.2.2.5)

treatment system degradation evaluated.

exposed to air -

indoor uncontrolled

(3.2.1-11)

3-209
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Loss of material A plant-specific Not Applicable Not applicable to

high-pressure due to erosion aging management BWRs (See SER

safety injection program is to be Section 3.2.2.2.6)

(charging) pump evaluated for

miniflow orifice erosion of the

exposed to treated orifice due to

borated water extended use of the

(3.2.1-12) centrifugal HPSI

pump for normal

charging.

Steel drywell and, Loss of material A plant-specific Not applicable Not applicable(See

suppression due to general aging management SER

chamber spray corrosion and program is to be Section 3.2.2.2.7)

system nozzle and fouling evaluated.

flow orifice internal

surfaces exposed to

air - indoor

uncontrolled

(internal)

(3.2.1-13)

Steel piping, piping Loss of material Water Chemistry Water Chemistry Consistent with

components, and due to general, and One-Time Control-BWR GALL Report which

piping elements pitting, and crevice Inspection (B.1.29.2); and recommends further

exposed to treated corrosion either One-Time evaluation (See

water Inspection (B.1.21) SER

(3.2.1-14) or Periodic Section 3.2.2.2.8,

Surveillance and Item 1) Preventive

Maintenance

program (B.1.22)

Steel containment Loss of material Water Chemistry Water Chemistry Consistent with

isolation piping, due to general, and One-Time Control-BWR GALL Report which

piping components, pitting, and crevice Inspection (B.1.29.2) and recommends further

and piping elements corrosion One-Time evaluation (See

intemal surfaces Inspection (B.1.21) SER

exposed to treated Section 3.2.2.2.8,

water Item 2)

(3.2.1-15)

Steel piping, piping Loss of material Lubricating Oil Oil Analysis Consistent with

components, and due to general, Analysis and Program (B.1.20) GALL Report which

piping elements pitting, and crevice One-Time and One-Time recommends further

exposed to corrosion Inspection Inspection (B.1.21) evaluation (See

lubricating oil SER

(3.2.1-16) Section 3.2.2.2.8,

Item 3)

3-210
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel (with or Loss of material Buried Piping and Buried Piping and Consistent with

without coating or due to general, Tanks Surveillance Tanks Inspection GALL Report which

wrapping) piping, pitting, crevice, and (B.1.1) recommends further

piping components, microbiologically- or evaluation (See

and piping elements influenced corrosion SER

buried in soil Buried Piping and Section 3.2.2.2.9)

(3.2.1-17) Tanks Inspection

Stainless steel Cracking due to BWR Stress Water Chemistry Consistent with

piping, piping stress corrosion Corrosion Cracking Control-BWR GALL Report, which

;components,-and cracking and and Water (B.1.29.2) and recommends no

piping elements intergranular stress Chemistry One-Time further evaluation

exposed to treated corrosion cracking Inspection (B.1.21) (See SER

water > 60 0C Section 3.2.2.1.1)

(> 140 0F)

(3.2.1-18)

Steel piping, piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with

components, and flow-accelerated Corrosion Corrosion (B.1.14); GALL Report, which

piping elements corrosion or Periodic recommends no exposed to steam Surveillance and. further evaluation or treated water Preventive (See SER

(3.2.1-19) Maintenance Section 3.2.2.1.2) ____ ___(B.1.22) ___ ____ 

Cast austenitic Loss of fracture Thermal Aging Not applicable Not applicable (See

stainless steel toughness due to Embrittlement of SER

piping, piping thermal aging CASS Section 3.2.2.1.8)

components, and embrittlement

piping elements

exposed to treated

water (borated or

unborated) > 250'C

(> 4820 F)

(3.2.1-20)

High-strength steel Cracking due to Bolting Integrity Not applicable Not applicable (See

closure bolting cyclic loading, SER

exposed to air with stress corrosion Section 3.2.2.1.8)

steam or water cracking

leakage

(3.2.1-21)

Steel closure Loss of material Bolting Integrity Not applicable Not applicable (See

bolting exposed to due to general SER

air with steam or corrosion Section 3.2.2.1.8)

water leakage

(3.2.1-22)

3-211
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel bolting and Loss of material Bolting Integrity Bolting Integrity Consistent with

closure bolting due to general, (B.1.12) GALL Report, which

exposed to air - pitting, and crevice recommends no

outdoor (external), corrosion further evaluation

or air - indoor (See SER

uncontrolled Section 3.2.2.1)

(external)

(3,2.1-23)

Steel closure Loss of preload due Bolting Integrity Bolting Integrity Consistent with

bolting exposed to to thermal:effects, (B.1.12) GALL Report, which

air - indoor gasket creep, and recommends no

uncontrolled self-loosening further evaluation

(external) (See SER

(3,2.1-24) Section 3.2.2.1.3)

Stainless steel Cracking due to Closed-Cycle Water Chemistry Consistent with

piping, piping stress corrosion Cooling Water Control-Closed GALL Report, which

components, and cracking System Cooling Water recommends no

piping elements (B.1.29.3) further evaluation

exposed to closed (See SER

cycle cooling water Section 3.2.2.1)

> 60'C (> 140'F)

(3,2.1-25)

Steel piping, piping Loss of material Closed-Cycle Not applicable Not applicable (See

components, and due to general, Cooling Water SER

piping elements pitting, and crevice System Section 3.2.2.1.8)

exposed to closed corrosion

cycle cooling water

(3,2.1-26)

Steel heat Loss of material Closed-Cycle Water Chemistry Consistent with

exchanger due to general, Cooling Water Control-Closed GALL Report, which

components pitting, crevice, and System Cooling Water recommends no

exposed to closed galvanic corrosion (B.1.29.3) further evaluation

cycle cooling water (See SER

(3.2.1-27) Section 3.2.2.1)

Stainless steel Loss of material Closed-Cycle Water Chemistry Consistent with

piping, piping due to pitting and Cooling Water Control-Closed GALL Report, which

components, piping crevice corrosion System Cooling Water recommends no

elements, and heat (B.1.29.3) further evaluation

exchanger (See SER

components Section 3.2.2.1).

exposed to

closed-cycle cooling

water

(3.2.1-28)

3-212
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Copper alloy piping, Loss of material Closed-Cycle Water Chemistry Consistent with

piping components, due to pitting, Cooling Water Control-Closed GALL Report, which

piping elements, crevice, and System Cooling Water recommends no

and heat exchanger galvanic corrosion (B.1.29.3) further evaluation

components (See SER

exposed to closed Section 3.2.2.1)

cycle cooling water

(3.2.1-29)

Stainless steel and Reduction of heat Closed-Cycle Not applicable Not applicable (See

copper alloy heat transfer due to Cooling Water SERi

exchanger tubes fouling System .. Section 3.2.2.1.8)

exposed to closed'

cycle cooling water

(3.2.1-30)

External surfaces of Loss of material External Surfaces External Surfaces Consistent with

steel components due to general Monitoring Monitoring (B.1.11) GALL Report (See

including ducting, corrosion SER

piping, ducting Section 3.2.2.1)

closure bolting, and

containment

isolation piping

external surfaces

exposed to air -

indoor uncontrolled

(external);

condensation

(external) and airoutdoor (external)

(3.2.1-31)

Steel piping and Loss of material Inspection of External Surfaces Consistent with

ducting components due to general Internal Surfaces in Monitoring (B.1.11) GALL Report, which

and internal corrosion Miscellaneous recommends no

surfaces exposed to Piping and Ducting Fire Protection-Fire further evaluation

air - indoor Components Water System (See SER

uncontrolled (B.1.13.2) Section 3.2.2.1.4)

(Internal)

(3.2.1-32) One-Time

Inspection (B.1.21)

Steel encapsulation Loss of material Inspection of Not applicable Not applicable (See

components due to general, Internal Surfaces in SER

exposedto air - pitting, and crevice Miscellaneous Section 3.2.2.1.8)

indoor uncontrolled corrosion Piping and Ducting

(internal) Components

(3.2.1-33)

3-213
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel piping, piping Loss of material Inspection of One-Time Consistent with

components, and due to general, Internal Surfaces in Inspection (B.1.21) GALL Report, which

piping elements pitting, and crevice Miscellaneous recommends no

exposed to corrosion Piping and Ducting Periodic further evaluation

condensation Components Surveillance and (See SER

(internal) Preventive Section 3.2.2.1.5)

(3.2.1-34) Maintenance

(B.1.22)

Steel containment Loss of material Open-Cycle Cooling Periodic Consistent with

isolation piping and due to general, Water System Surveillance and GALL Report, which

components pitting, crevice, and Preventive recommends no

internal surfaces microbiologically- Maintenance further evaluation

exposed to raw influenced (B.1.22) (See SER

water corrosion, and Section 3.2.2.1.6)

(3.2.1-35) fouling

Steel heat Loss of material Open-Cycle Cooling Service Water Consistent with

exchanger due to general, Water System Integrity (B.1.26) or GALL Report, which

components pitting, crevice, Periodic recommends no

exposed to raw galvanic, and Surveillance and further evaluation

water microbiologically - Preventive (See SER

(3.2.1-36) influenced Maintenance Section 3.2.2.1.7)

corrosion, and (B.1.22)

fouling

Stainless steel Loss of material Open-Cycle Cooling Service Water Consistent with

piping, piping due to pitting, Water System Integrity (B.1.26) GALL Report, which

components, and crevice, and recommends no

piping elements microbiologically - further evaluation

exposed to raw influenced corrosion (See SER

water Section 3.2.2.1.7)

(3.2.1-37)

Stainless steel Loss of material Open-Cycle Cooling Not Applicable Not applicable (See

containment due to pitting, Water System. SER

isolation piping and crevice, and Section 3.2.2.1.8)

components microbiologically - internal surfaces influenced

exposed to raw corrosion, and

water fouling

(3.2.1-38)

Stainless steel heat Loss of material Open-Cycle Cooling Service Water Consistent with

exchanger due to pitting, Water System Integrity (B.1.26) GALL Report, which

components crevice, and recommends no

exposed to raw microbiologically - further evaluation

water influenced (See SER

(3.2.1-39) corrosion, and Section 3.2.2.1.7)

fouling

3-214
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel and stainless Reduction of heat Open-Cycle Cooling Service Water Consistent with

steel heat transfer due to Water System Integrity (B.1.26) GALL Report, which

exchanger tubes fouling recommends no

(serviced by further evaluation

open-cycle cooling (See SER

water) exposed to Section 3.2.2.1)

raw water

(3.2.1-40)

Copper alloy Loss of material Selective Leaching Selective Leaching Consistent with

> 15% Zn piping, dueto selective of Materials (B.1.25) GALL Report, which

piping components, leaching recommends no

piping elements, further evaluation

and heat exchanger (See SER

components Section 3.2.2.1)

exposed to closed

cycle cooling water

(3.2.1-41)

Gray cast iron Loss of material Selective Leaching Selective Leaching Consistent with

piping, piping due to selective of Materials (B.1.25) GALL Report, which

components, piping leaching recommends no

elements exposed further evaluation

to closed-cycle (See SER

cooling water Section 3.2.2.1)

(3.2.1-42)

Gray cast iron Loss of material Selective Leaching Not applicable Not applicable (See

piping, piping due to selective of Materials SER

components, and leaching Section 3.2.2.1.8)

piping elements

exposed to soil

(3.2.1-43)

Gray cast iron Loss of material Selective Leaching Not applicable Not applicable (See

motor cooler due to selective of Materials SER

exposed to treated leaching Section 3.2.2.1.8)

water

(3.2.1-44)

Aluminum, copper Loss of material Boric Acid Not Applicable Not applicable to

alloy > 15% Zn, and due to Boric acid Corrosion BWRs

steel external corrosion

surfaces, bolting,

and piping, piping

components, and

piping elements

exposed to air with

borated water

leakage

(3.2.1-45)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel encapsulation Loss of material Inspection of Not Applicable Not applicable to

components due to general, Internal Surfaces in BWRs

exposed to air with pitting, crevice and Miscellaneous

borated water boric acid corrosion Piping and Ducting

leakage (internal) Components

(3.2.1-46)

Cast austenitic Loss of fracture Thermal Aging Not Applicable Not applicable to

stainless steel toughness due to Embrittlement of BWRs

piping, piping thermal aging CASS

components, and embrittlement

piping elements

exposed to treated

borated water

> 250'C (> 482°F)

(3.2.1-47)

Stainless steel or Cracking due to Water Chemistry Not Applicable Not applicable to

stainless-steel-clad stress corrosion BWRs

steel piping, piping cracking

components, piping

elements, and tanks

(including safety

injection

tanks/accumulators)

exposed to treated

borated water

> 60 0C (> 140'F)

(3.2.1-48)

Stainless steel Loss of material Water Chemistry Not Applicable Not applicable to

piping, piping due to pitting and BWRs

components, piping crevice corrosion

elements, and tanks

exposed to treated

borated water

(3.2.1-49)

Aluminum piping, None None None Consistent with

piping components, GALL Report

and piping elements

exposed to air -

indoor uncontrolled

(internal/external)

(3.2.1-50)

Galvanized steel None None Not Applicable Not Applicable (See

ducting exposed to SER

air - indoor Section 3.2.2.1.8)

controlled (external)

(3.2.1-51)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Glass piping None None None Consistent with

elements exposed GALL Report

to air - indoor

uncontrolled

(external),

lubricating oil, raw

water, treated

water, or treated

borated water

(3.2.1-52)

Stainless steel, None None None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping components,

and piping elements

exposed to air - indoor uncontrolled

(extemal)

(3.2.1-53)

Steel piping, piping None None Not applicable Not applicable (See

components, and SER

piping elements Section 3.2.2.1.8)

exposed to air -

indoor controlled

(extemal)

(3.2.1-54)

Steel and stainless None None Not applicable Not applicable (See

steel piping, piping SER

components, and Section 3.2.2.1.8)

piping elements in

concrete

(3.2.1-55)

Steel, stainless None None None Consistent with

steel, and copper GALL Report

alloy piping, piping

components, and

piping elements

exposed to gas

(3.2.1-56)

Stainless steel and None None Not Applicable Not applicable to

copper alloy BWRs

< 15% Zn piping,

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.2.1-57)

The staff's review of the engineered safety features

several approaches. One approach, documented in

systems component groups followed one of

SER Section 3.2.2.1, discusses the staff's

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review of the AMR results for components that the applicant indicated are consistent with the

GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.2.2.2, discusses the staff's review of the AMR results for components that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended, A third approach, documented in SER Section 3.2.2.3, discusses the staff's

review of the AMR results for components that the applicant indicated are not consistent with,

or not addressed in, the GALL Report. The staff's review of AMPs that are credited to manage

or monitor aging effects of the engineered safety features systems components is documented

in SER Section 3.0.3.

3.2.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the engineered safety features systems

components:

" Buried Piping and Tanks Inspection Program

" External Surfaces Monitoring Program

" Flow-Accelerated Corrosion Program

" Heat Exchanger Monitoring Program

" Oil Analysis Program

" One-Time Inspection Program

" Periodic Surveillance and Preventive Maintenance Program

" Selective Leaching Program

* Service Water Integrity Program

" Water Chemistry Control - BWR Program

* Water Chemistry Control - Closed Cooling Water Program

* Bolting Integrity Program

In LRA Tables 3.2.2-1 through 3.2.2-7, 3.3.2-14-1 through 3.2.2-14- 4, 3.3.2-14-7, 3.3.2-14-8,

3.3.2-14-10, and 3.3.2-14-14, the applicant provided a summary of AMRs for the engineered

safety features systems components and identified which AMRs it considered to be consistent

with the GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report does not

recommend further evaluation, the staff performed an audit and review to determine whether

the plant-specific components contained in these GALL Report component groups were

bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

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GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant is consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect.ý In addition, the

AMP is consistent with the AMP identified by the GALL Report. This note indicates that the

applicant was unable to find a listing of some system components in the GALL Report;

however, the applicant identified a different component in the GALL Report that has the same

material, environment, aging effect, and AMP as the component that was under review. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the AMR line item of the different component was applicable to the

component under review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these

line items to verify consistency with the GALL Report. The staff verified whether the AMR line

item of the different component was applicable to the component under review. The staff

verified whether the identified exceptions to the GALL AMPs had been reviewed and accepted

by the staff. The staff also determined whether the AMP identified by the applicant was

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the

site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified in the GALL

Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided 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 is discussed below.

3.2.2.1.1 Cracking due to Stress Corrosion Cracking and Intergranular Stress Corrosion

Cracking

LRA Table 3.2.1, Item 3.2.1-18, addresses cracking due to stress corrosion cracking (SCC) and

intergranular stress corrosion cracking (IGSCC) for stainless steel piping, piping components,

and piping elements exposed to treated water >601C (>1400 F) in the ESF systems. The LRA

credits the Water Chemistry Control-BWR Program together with the One-Time Inspection

Program. GALL Report recommends AMPs XI.M7, "BWR Stress Corrosion Cracking," and the

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XI.M2, "Water Chemistry," to manage this aging effect. The LRA states that none of the ESF

system components are within the scope of the BWR Stress Corrosion Cracking Program. The

AMR line items in LRA Table 2 that reference this line item in GALL Report Table 1 cite Generic

Note E, indicating that the AMR line items are consistent with NUREG-1801 material,

environment, and aging effect, but a different aging management program is credited.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry

Control-BWR Program and its evaluations are documented in SER Sections 3.0.3.1.6 and

3.0.3.1.10, respectively. The staff determined that Water Chemistry Control-BWR Program

include activities that are consistent with the recommendations in the GALL AMP X.M2 to

maintain high water purity, which is effective for managing cracking due to SCC and IGSCC for

stainless steel components exposed to treated water. The staff confirmed that the One-Time

Inspection Program will be used to verify the effectiveness of the applicant's Water Chemistry

Control-BWR Program to manage cracking.

During the audit and review, the staff also asked the applicant for additional information on the

components addressed by this AMR and why they are not within the scope of the BWR SCC

Program. In its response, the applicant stated that the BWR SCC Program is applicable to all

BWR piping and piping welds made of austenitic stainless steel and nickel alloy that are 4

inches or larger NPS, and contain reactor coolant at a temperature above 93 0C (2000 F) during

power operation. The components addressed by this AMR line items are less than 4 inches

NPS and are outside the reactor coolant system pressure boundary; therefore, they are outside

the scope of the BWR SCC Program. The applicant also stated that the components addressed

by this AMR line item are included within the scope of the JAFNPP Inservice Inspection

Program.

The staff reviewed the applicant's BWR SCC Program and its evaluation is documented in SER

Section 3.0.3.2.5. The staff determined that the components addressed by this AMR line item

are outside the scope of the BWR SCC Program. Since they are included in the Inservice

Inspection Program, they will be inspected periodically, which will ensure that any cracking will

be detected and corrective actions taken. The staff also reviewed GALL AMP XI.M7 and

determined that it includes water chemistry control along with inservice inspections to manage

SCC and IGSCC. Since the applicant is crediting the Water Chemistry Control-BWR Program,

and the components are within the scope of the ISI Program, the staff finds that the activities

being credited are consistent with the GALL Report recommendations to manage these aging

effects. On this basis, the staff finds the AMR results for this line item acceptable.

3.2.2.1.2 Wall Thinning due to Flow-Accelerated Corrosion

LRA Table 3.2.1, Item 3.2.1-19, addresses wall thinning due to flow-accelerated corrosion for

steel piping, piping components, and piping elements exposed to steam or treated water in the

ESF systems. The LRA credits the Flow-Accelerated Corrosion (FAC) Program, or the Periodic

Surveillance and Preventive Maintenance Program to manage this aging effect. GALL Report

recommends GALL AMP XI.M17, "Flow-Accelerated Corrosion," to manage this aging effect.

The AMR line items in LRA Table 2 that reference this line item in GALL Report Table 1 credit

the Periodic Surveillance and Preventive Maintenance Program and cite Generic Note E,

indicating that the AMR line items are consistent with NUREG-1801 material, environment, and

aging effect, but a different aging management program is credited.

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During the audit and review, the staff asked the applicant to clarify why the Periodic

Surveillance and Preventive Maintenance Program is credited for some components addressed

by this AMR instead of the FAC Program. In its response, the applicant stated that augmented

inspections are performed at JAFNPP on selected piping components that are not part of the

inspections required by applicant's Generic Letter 89-08 program, which are performed under

the GALL AMP XI.M17 Program. These inspections are the same as those performed under

the FAC Program, but are included in the Periodic Surveillance and Preventive Maintenance

Program for administrative reasons since the aging effect is not FAC.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and determined that this aging management program includes measurement of wall thickness

for the RCIC piping to detect loss of material due to erosion. This is the same activity that would

be performed Under the FAC program, and acceptance criteria are established in accordance

With the FAC Program. Since these inspections are the same as those performed under the

FAC Program, the activities are consistent with the recommendations in GALL AMP XI.M17 to

manage wall thinning due to flow-accelerated corrosion for steel components exposed to steam

or treated water. On this basis, the staff finds the AMR results for this line item acceptable.

3.2.2.1.3 Loss of Material due to Thermal Effects, Gasket Creep, and Self-Loosening

LRA Table 3.2.1, Item 3.2.1-24, addresses loss of preload due to thermal effects, gasket creep,

and self-loosening for steel closure bolting exposed to air-indoor uncontrolled (external) in the

ESF systems. The LRA states that this aging effect is not applicable since loss of preload is a

design driven effect and not an aging effect requiring management. GALL Report recommends

AMP XI.M18, "Bolting Integrity," to manage this aging effect.

During the audit and review, the staff asked the applicant to clarify why this aging effect is not

applicable at JAFNPP. In its response, the applicant stated that this position is consistent with

the EPRI Mechanical Tools report (EPRI 1010639); however, the bolting integrity program is

currently used at JAFNPP to monitor these components. The applicant committed to amend the

LRA to delete "Not Applicable" from this AMR line item.

In its letter dated February 1, 2007, the applicant amended the LRA to delete "Not Applicable"

from this AMR line item. The staff reviewed the applicant's bolting integrity program and

determined that it is consistent with the recommendations in GALL AMP XI.M18, and includes

activities that will manage loss of preload for these components. On this basis, the staff finds

this AMR acceptable.

3.2.2.1.4 Loss of Material due to General Corrosion

LRA Table 3.2.1, Item 3.2.1-32, addresses loss of material due to general corrosion for steel

piping and ducting components, and internal surfaces exposed to air-indoor uncontrolled

(internal) in the ESF systems. The LRA credits the External Surfaces Monitoring Program, Fire

Protection Program, Fire Water System Program, or the One-Time Inspection Program to

manage this aging effect. GALL Report recommends AMP XI.M38, "Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components," to manage this aging effect. The

AMR line items in LRA Table 2 that reference this line item in GALL Report Table 1 cite Generic

Note E; indicating that the AMR line items are consistent with GALL Report material,

environment, and aging effect, but a different aging management program is credited.

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GALL AMP XI.M38 includes periodic visual inspections of internal surfaces of components that

are not included in other aging management programs for loss of material. The inspections are

performed when the internal surfaces are accessible during the performance of periodic

surveillances, during maintenance activities, or during scheduled outages. The staff reviewed

the applicant's External Surfaces Monitoring Program, Fire Protection Program, Fire Water

System Program, and One-Time Inspection Program and its evaluations are documented in

SER Sections 3.0.3.2.9, 3.0.3.2.11, 3.0.3.2.12, and 3.0.3.1.6, respectively. The staff finds that

the applicant's External Surfaces Monitoring Program includes inspections of external surfaces

that are appropriate for managing loss of material from internal surfaces when the internal and

external material and environment combinations are the same, such that external surface

condition is representative of internal surface condition. The applicant's Fire Protection Program

and Fire Water System Program include tests and inspections of fire protection equipment that

will detect loss of material due to corrosion. The staff determined that the One-Time Inspection

Program is credited for managing loss of material for piping in the radwaste and plant drains

system, which is not continuously wetted and for which aging due to corrosion is not anticipated

to be significant. The staff finds this acceptable since the one-time inspection will confirm that

no significant corrosion is occurring in these components. On the basis of its review, the staff

determined that the applicant's External Surfaces Monitoring Program, Fire Protection Program,

Fire Water System program, and One-Time Inspection Program include inspections that

provide the same level of assurance for managing loss of material as GALL AMP XI.M38

program, and are adequate to manage loss of material due to general corrosion for steel

components exposed to air-indoor uncontrolled for the components addressed by this AMR. On

this basis, the staff finds the AMR results for this line item acceptable.

3.2.2.1.5 Loss of Material due to General, Pitting, and Crevice Corrosion

LRA Table 3.2.1, Item 3.2.1-34, addresses loss of material due to general, pitting, and crevice

corrosion for steel piping, piping components, and piping elements exposed to condensation

(internal) in the ESF systems. The LRA credits the One-Time Inspection Program or the

Periodic Surveillance and Preventive Maintenance Program to manage this aging effect. GALL

Report recommends AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components," to manage this aging effect. The AMR line items in LRA Table 2 that

reference this line item in GALL Report Table 1 cite Generic Note E, indicating that the AMR

line items are consistent with GALL Report material, environment, and aging effect, but a

different aging management program is credited.

The staff reviewed the applicant's One-Time Inspection Program and Periodic Surveillance and

Preventive Maintenance Program and its evaluations are documented in SER

Sections 3.0.3.1.6 and 3.0.3.3.4, respectively. The staff determined that these aging

management programs which include inspections of internal surfaces consistent with GALL

AMP XI.M38 that are adequate to manage loss of material for the components addressed by

this AMR. The staff determined that the Periodic Surveillance and Preventive Maintenance

Program includes periodic inspections that are performed as part of routine plant surveillance

and preventive maintenance activities. These inspections will detect loss of material on the

internal surfaces of piping and piping components in a timely manner such that corrective

actions can be taken prior to a loss of component intended function. The staff also determined

that the One-Time Inspection Program is credited for components in the high pressure coolant

injection system that are exposed to untreated air that may contain moisture. Loss of material is

not expected to be a significant aging effect for these components since they are not

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continuously exposed to moisture. Therefore, the staff considers the One-Time Inspection

Program adequate to verify the absence of this aging effect for these components. On this

basis, the staff finds the AMR results for this line item acceptable.

3.2.2.1.6 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion, and Fouling

LRA Table 3.2.1, Item 3.2.1-35, addresses loss of material due to general, pitting, crevice, and

MIC, and fouling for steel containment isolation piping and components internal surfaces

exposed to raw water in the ESF systems. The LRA credits the Periodic Surveillance and

Preventive Maintenance Program to manage this aging effect. GALL Report recommends

GALL AMP XI.M20, "Open-Cycle Cooling Water System," to manage this aging effect. The

AMR line items in LRA Table 2 that reference this line item in GALL Report Table 1 cite Generic

Note E, indicating that the AMR line items are consistent with GALL Report material,

environment, and aging effect, but a different aging management program is credited.

During the audit and review, the staff asked the applicant to clarify why this AMR line item does

not credit applicant's Service Water Integrity Program for these components. In its response,

the applicant stated that the components addressed in this AMR line item are in containment

isolation penetrations for drains from the drywell floor and equipment sumps. As such, the

internal raw water environment for the components is drainage from containment, which is not

the raw lake-water. Therefore, these components are not within the scope of the Service Water

Integrity Program.

The staff determined that the components addressed by this AMR line item are not within the

scope of the Service Water Integrity Program since they are not exposed to raw service water.

The staff also determined that, since these components are intermittently exposed to drainage

water only, loss of material will not be as severe as for components continuously exposed to

service water.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this aging

management program includes periodic inspections consistent with GALL AMP XI.M20, that will

detect loss of material in a timely manner such that corrective actions can be taken prior to a

loss of component intended function. As such, the staff finds the applicant's Periodic

Surveillance and Preventive Maintenance Program adequate to manage loss of material for the

components addressed by this AMR line item. On this basis, the staff finds this AMR results for

this line item acceptable.

3.2.2.1.7 Loss of Material due to General, Pitting, Crevice, Galvanic, and

Microbiologically-Influenced Corrosion, and Fouling

LRA Table 3.2.1, Item 3.2.1-36, addresses loss of material due to general, pitting, crevice,

galvanic, and MIC, and fouling for steel heat exchanger components exposed to raw water in

the ESF systems. The LRA credits the Service Water Integrity Program or Periodic Surveillance

and Preventive Maintenance Program to manage this aging effect. GALL Report recommends

AMP XI.M20, "Open-Cycle Cooling Water System," to manage this aging effect. The AMR line

items in LRA Table 2 that reference this line item in GALL Report Table 1 and credit the

Periodic Surveillance and Preventive Maintenance Program cite Generic Note E, indicating that

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the AMR line items are consistent with NUREG-1801 material, environment, and aging effect,

but a different aging management program is credited.

During the audit and review, the staff asked the applicant to clarify why the AMR line items do

not credit applicant's Service Water Integrity Program for these components. In its response,

the applicant stated that the components addressed in this AMR line item are in the standby

gas treatment system and are drains for water accumulation or condensation from the various

components in the system. As such, the internal raw water environment for the components is

condensation or drainage, which is not the raw lake-water used in the service water systems.

Therefore, these components are not within the scope of the Service Water Integrity Program.

The staff determined that the components addressed by this AMR line item are not within the

scope of the Service Water Integrity Program since they are not exposed to raw service water.

The staff also determined that, since these components are intermittently exposed to drainage

water only, loss of material will not be as severe as for components continuously exposed to

service water. The staff reviewed the applicant's Periodic Surveillance and Preventive

Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff

determined that this Aging Management Program includes periodic inspections consistent with

GALL AMP XI.M20, that will detect loss of material in a timely manner such that corrective

actions can be taken prior to a loss of component intended function. As such, the staff finds the

Periodic Surveillance and Preventive Maintenance Program adequate to manage loss of

material for the components addressed in this AMR. On this basis, the staff finds the AMR

results for this line item acceptable.

3.2.2.1.8 AMR Results Identified as Not Applicable

In LRA Table 3.2.1, line Items 20, 21, 22, 26, 30, 33, 38, 43, 44, 51, 54, 55, and 57 are

identified as "Not Applicable" since the component/material/ environment combination does not

exist at JAFNPP or a different GALL Report Table 1 AMR line item was credited to manage the

aging effect. For each of these line items, the staff reviewed the LRA and the applicant's

supporting documents, and confirmed the applicant's claim that the

component/material/environment combination does not exist at JAFNPP or the Table 1 AMR

line item credited is acceptable.

On the basis that JAFNPP does not have the component/material/ environment combination for

these GALL Report Table 1 line items, the staff finds that these AMR line items are not

applicable to JAFNPP.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing the associated aging effects. On the basis of its review,

the staff concludes that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are indeed consistent with the AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

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Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for

the engineered safety features systems components. The applicant provided information

concerning how it will manage the following aging effects:

* cumulative fatigue damage

* loss of material due to cladding

* loss of material due to pitting and crevice corrosion

* reduction of heat transfer- due to fouling

* hardening and loss of strength due to elastomer degradation

* loss of material due to erosion

* loss of material due to general corrosion and fouling

" loss of material due to general, pitting, and crevice corrosion

" loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion

" QA for aging management of nonsafety-related components

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The

staff's evaluation of the aging effects is discussed in the following sections.

3.2.2.2.1 Cumulative Fatigue Damage

The staff reviewed LRA Section 3.2.2.2.1 against the SRP-LR Section 3.2.2.2.1 criteria.

SRP-LR Section 3.2.2.2.1states that fatigue is a time-limited aging analysis (TLAA) as defined

in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1).

This TLAA is addressed separately in Section 4.3, "Metal Fatigue Analysis," of SRP-LR.

SER Section 4.3.2.2 documents the staffs review of the applicant's evaluation of this TLAA for

Non-Class 1 components, including non-class 1 portions of the emergency safety features

systems.

3.2.2.2.2 Loss of Material Due to Cladding Breach

SRP-LR Section 3.2.2.2.2 addresses loss of material due to cladding breach for PWR steel

pump casings with stainless steel cladding exposed to treated borated water. This further

evaluation is not applicable since JAFNPP is a BWR plant.

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On the basis that JAFNPP does not have any components subject to this aging effect, the staff

finds that this aging effect does not require management at JAFNPP.

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 SRP-LR Section 3.2.2.2.3 criteria.

(1) In LRA Section 3.2.2.2.3, Item 1, the applicant addressed loss of material due to pitting

and crevice corrosion for internal surfaces of stainless steel containment isolation

piping, piping components, and piping elements exposed to treated water. The applicant

stated that this aging effect is managed by the Water Chemistry Control - BWR

Program. The effectiveness of the Water Chemistry Control - BWR Program will be

confirmed by the One-Time Inspection Program through an inspection of a

representative sample of components crediting this program including susceptible

locations such as areas of stagnant flow.

SRP-LR Section 3.2.2.2.3, Item 1, states that loss of material due to pitting and crevice

corrosion could occur for internal surfaces of stainless steel containment isolation

piping, piping components, and piping elements exposed to treated water. The existing

AMP relies on monitoring and control of water chemistry to mitigate degradation.

However, control of water chemistry does not preclude loss of material due to pitting and

crevice corrosion at locations of stagnant flow conditions. Therefore, the effectiveness of

the chemistry control program should be verified to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to verify the

effectiveness of the chemistry control program. A one-time inspection of select

components at susceptible locations is an acceptable method to determine whether an

aging effect is not occurring or an aging effect is progressing very slowly such that the

component's intended function will be maintained during the period of extended

operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with recommendations in GALL Report,

and are adequate to manage loss of material due to pitting and crevice corrosion for

internal surfaces of stainless steel containment isolation piping, piping components, and

piping elements exposed to treated water. On this basis, the staff finds that the applicant

has met the criteria of SRP-LR Section 3.2.2.2.3, Item 1, for further evaluation.

(2) In LRA Section 3.2.2.2.3, Item 2, the applicant addressed loss of material from pitting

and crevice corrosion for stainless steel piping, piping components, and piping elements

exposed to soil. The applicant stated that this aging effect is managed by the Buried

Piping and Tanks Inspection Program. The Buried Piping and Tanks Inspection

Program will include (a) preventive measures to mitigate corrosion and (b) inspections to

manage the effects of corrosion on the pressure-retaining capability of buried carbon

steel, copper alloy, gray cast iron, and stainless steel components. Buried components

will be inspected when excavated during maintenance. An inspection will be performed

within ten years of entering the period of extended operation, unless an opportunistic

inspection occurred within this ten-year period.

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SRP-LR Section 3.2.2.2.3, Item 2, states that loss of material from pitting and crevice

corrosion could occur for stainless steel piping, -piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that the aging effect is adequately managed.

The staff reviewed the applicant's Buried Piping and Tanks Inspection Program and its

evaluation is documented in SER Section 3.0.3.2.1. The staff determined that this

program includes activities that are consistent with the recommendations in GALL

Report, and are adequate to manage loss of material from pitting and crevice corrosion

for stainless steel piping, piping components, and piping elements exposed to soil. The

staff confirmed that inspections will be performed both during the 10-year period

immediately prior to the period of extended operation, as well as during the 10-year

period after entering the period of extended operation, as recommended in GALL

Report. On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.3, Item 2, for further evaluation.

(3) In LRA Section 3.2.2.2.3, Item 3, the applicant addressed loss of material from pitting

and crevice corrosion for BWR stainless steel and aluminum piping, piping components,

and piping elements exposed to treated water. The applicant stated that this aging effect

is managed by the Water Chemistry Control - BWR Program for stainless steel

components. There are no aluminum components exposed to treated water in the ESF

systems. The effectiveness of the Water Chemistry Control - BWR Program will be

confirmed by the One-Time Inspection Program through an inspection of a

representative sample of components crediting this program including susceptible

locations such as areas of stagnant flow.

SRP-LR Section 3.2.2.2.3, Item 3, states that loss of material from pitting and crevice

corrosion could occur for BWR stainless steel and aluminum piping, piping components,

and piping elements exposed to treated water. The existing AMP relies on monitoring

and control of water chemistry for BWRs to mitigate degradation. However, control of

water chemistry does not preclude loss of material due to pitting and crevice corrosion

at locations of stagnant flow conditions. Therefore, the effectiveness of the chemistry

control program should be verified to ensure that corrosion is not occurring. The GALL

Report recommends further evaluation of programs to verify the effectiveness of the

water chemistry control program. A one-time inspection of select components at

susceptible locations is an acceptable method to determine whether an aging effect is

not occurring or an aging effect is progressing very slowly such that the component's

intended function will be maintained during the period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in GALL

Report, and are adequate to manage loss of material from pitting and crevice corrosion

for BWR stainless steel piping, piping components, and piping elements exposed to

treated water. The staff also confirmed that there are no aluminum components

exposed to treated water in the ESF systems. On this basis, the staff finds that the

applicant has met the criteria of SRP-LR Section 3.2.2.2.3, Item 3, for further evaluation.

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(4) In LRA Section 3.2.2.2.3, Item 4, the applicant addressed loss of material from pitting

and crevice corrosion for stainless steel and copper alloy piping, piping components,

and piping elements exposed to lubricating oil. The applicant stated that this aging effect

is managed by the Oil Analysis Program, which includes periodic sampling and analysis

of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. During the past five years, many visual

inspections of components containing lubricating oil have been performed during

corrective and preventive maintenance activities. The visual inspections of these

components would identify degraded conditions such as fouling, corrosion or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one-time inspection to provide confirmation of the

effectiveness of the Oil Analysis Program.

SRP-LR Section 3.2.2.2.3, Item 4, states that loss of material from pitting and crevice

corrosion could occur for stainless steel and copper alloy piping, piping components,

and piping elements exposed to lubricating oil. The existing program relies on the

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits, thereby preserving an environment that is not conducive to corrosion.

However, control of lube oil contaminants may not always have been adequate to

preclude corrosion. Therefore, the effectiveness of lubricating oil control should be

verified to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation to verify the effectiveness of the lubricating oil program. A one-time

inspection of selected components at susceptible locations is an acceptable method to

ensure that corrosion is not occurring and that the component's intended function will be

maintained during the period of extended operation.

The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection

Program and its evaluations are documented in SER Sections 3.0.3.2.14 and 3.0.3.1.6,

respectively.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP. In its response, the

applicant stated that the LRA will be amended to add activities to confirm the

effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its letter dated February 1, 2007, the applicant amended the LRA Section 3.2.2.2.3,

Item 4 to state "One-time Inspection Program activities will be utilized to confirm the

effectiveness of the Oil Analysis Program.", The staff finds that the use of a one-time

inspection to verify the effectiveness of the oil analysis program is consistent with the

recommendations in GALL Report, and is acceptable.

The staff determined that the applicant's Oil Analysis Program includes periodic.

sampling and analysis of lubricating oil to maintain contaminants within acceptable

limits. The staff finds that these activities are consistent with the recommendations in

GALL Report, and are adequate to manage loss of material from pitting and crevice

corrosion for stainless steel and copper alloy piping, piping components, and piping

elements exposed to lubricating oil.

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On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.3, Item 4, for further evaluation.

(5) In LRA Section 3.2.2.2.3, Item 5, the applicant addressed loss of material from pitting

and crevice corrosion for partially encased stainless steel tanks exposed to raw water

due to cracking of the perimeter seal from weathering. The applicant stated that at

JAFNPP there are no outdoor stainless steel tanks in the ESF systems. This item is

therefore not applicable.

The staff confirmed that there are no outdoor stainless steel tanks in the ESF systems

at JAFNPP. On the basis that JAFNPP does not have any components subject to this

aging effect, the staff finds that this aging effect does not require management at

JAFNPP.

(6) In LRA Section 3.2.2.2.3, Item 6, the applicant addressed loss of material from pitting

and crevice corrosion for stainless steel piping, piping components, piping elements,

and tanks exposed to internal condensation. The applicant stated that this aging effect

is managed by the One-Time Inspection Program. This program uses visual and other

NDE techniques to confirm that loss of material is not occurring or is so insignificant that

an Aging Management Program for these components is not warranted.

SRP-LR Section 3.2.2.2.3, Item 6, states that loss of material from pitting and crevice

corrosion could occur for stainless steel piping, piping components, piping elements,

and tanks exposed to internal condensation. The GALL Report recommends further

evaluation of a plant-specific AMP to ensure that the aging effect is adequately

managed.

Based on industry operating experience, the staff recognizes that stainless steel

components exposed to condensation are not expected to experience significant

degradation. As such, the staff considers a one-time inspection to confirm that

significant degradation is not occurring adequate to manage this aging effect. The staff

reviewed the applicant's One-Time Inspection Program and its evaluation is

documented in SER Section 3.0.3.1.6. The staff determined that this program includes

inspections and NDE techniques that are consistent with the recommendations in GALL

Report, and are adequate to detect loss of material from pitting and crevice corrosion for

stainless steel piping, piping components, piping elements, and tanks exposed to

internal condensation. On this basis, the staff finds that the applicant has met the criteria

of SRP-LR Section 3.2.2.2.3, Item 6, for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.3. For those line items that apply to LRA Section 3.2.2.2.3,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.2.2.2.4 against the SRP-LR Section 3.2.2.2.4 criteria.

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(1) In LRA Section 3.2.2.2.4, Item 1, the applicant addressed reduction of heat transfer due

to fouling for steel, stainless steel, and copper alloy heat exchanger tubes exposed to

lubricating oil. The applicant stated that this aging effect is managed by the Oil Analysis

Program for copper alloy heat exchanger tubes. There are no stainless steel or steel

heat exchanger tubes exposed to lubricating oil in the ESF systems. The Oil Analysis

Program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits, thereby preserving an environment that is not

conducive to fouling. During the past five years, many visual inspections of components

containing lubricating oil have been performed during corrective and preventive

maintenance activities. The visual inspections of these components would identify

degraded conditions such as fouling, corrosion or cracking that could be attributed to an

ineffective Oil Analysis Program. These past inspections at JAFNPP serve in lieu of a

one-time inspection to provide confirmation of the effectiveness of the Oil Analysis

Program.

SRP-LR Section 3.2.2.2.4, Item 1, states that reduction of heat transfer due to fouling

could occur for steel, stainless steel, and copper alloy heat exchanger tubes exposed to

lubricating oil. The existing AMP relies on monitoring and control of lube oil chemistry to

mitigate reduction of heat transfer due to fouling. However, control of lube oil chemistry

may not always have been adequate to preclude fouling. Therefore, the effectiveness of

lube oil chemistry control should be verified to ensure that fouling is not occurring. The

GALL Report recommends further evaluation of programs to verify the effectiveness of

lube oil chemistry control. A one-time inspection of selected components at susceptible

locations is an acceptable method to determine whether an aging effect is not occurring

or an aging effect is progressing very slowly such that the component's intended

function will be maintained during the period of extended operation.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP. In its response, the

applicant stated that the LRA will be amended to add activities to confirm the

effectiveness of the Oil Analysis Program to the One-Time Inspection AMP. In its

response dated February 1, 2007, the applicant amended LRA Section 3.2.2.2.4, Item 1,

to state "One-time Inspection Program activities will be utilized to confirm the

effectiveness of the Oil Analysis Program." The staff finds that the use of a one-time

inspection to verify the effectiveness of the oil analysis program is consistent with the

recommendations in GALL Report, and is acceptable.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is

documented in SER Section 3.0.3.2.14. The staff determined that this program includes

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits. The staff finds that these activities are consistent with the

recommendations in GALL Report, and are adequate to manage reduction of heat

transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger tubes

exposed to lubricating oil. On this basis, the staff finds that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.4, Item 1, for further evaluation.

(2) In LRA Section 3.2.2.2.4, Item 2, the applicant addressed reduction of heat transfer due

to fouling for stainless steel heat exchanger tubes exposed to treated water. The

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applicant stated that this aging effect is managed by the Water Chemistry Control -

BWR Program. The effectiveness of the Water Chemistry Control - BWR Program will

be confirmed by the One-Time Inspection Program through an inspection of a

representative sample of components crediting this program, including susceptible

locations such as areas of stagnant flow.

SRP-LR Section 3.2.2.2.4, Item 2, states that reduction of heat transfer due to fouling

could occur for stainless steel heat exchanger tubes exposed to treated water. The

existing program relies on control of water chemistry to manage reduction of heat

transfer due to fouling. However, control of water chemistry may have been inadequate.

Therefore, the GALL Report recommends that the effectiveness of the chemistry control

program should be verified to ensure that reduction of heat transfer due to fouling is not

occurring. A one-time inspection is an acceptable method to ensure that reduction of

heat transfer is not occurring and that the component's intended function will be

maintained during the period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in GALL

Report, and are adequate to manage reduction of heat transfer due to fouling of

stainless steel heat exchanger tubes exposed to treated water. On this basis, the staff

finds that the applicant has met the criteria of SRP-LR Section 3.2.2.2.4, Item 2, for

further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.4. For those line items that apply to LRA Section 3.2.2.2.4,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

In LRA Section 3.2.2.2.5, the applicant stated that at JAFNPP there are no elastomeric

components in the ESF systems; therefore, this item is not applicable to JAFNPP.

The staff reviewed the LRA and basis document and confirmed that there are no elastomeric

components in the ESF systems at JAFNPP. On the basis that JAFNPP does not have any

components subject to this aging effect, the staff finds that this aging effect does not require

management at JAFNPP.

3.2.2.2.6 Loss of Material Due to Erosion

This further evaluation addresses stainless steel high pressure safety injection (HPSI) pump

miniflow recirculation orifice exposed to treated borated water. JAFNPP is a BWR and has no

HPSI pump miniflow orifice; therefore, this item is not applicable.

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling

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The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

In LRA Section 3.2.2.2.7, the applicant addressed 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 air - indoor uncontrolled. The applicant stated that at JAFNPP the spray

nozzles are copper alloy and are not subject to loss of material due to general corrosion in an

indoor air environment. There are also no steel orifices in drywell and suppression chamber

spray systems exposed to an indoor air environment (internal).

SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling can

occur for steel drywell and suppression chamber spray system nozzle and flow orifice internal

surfaces exposed to air - indoor uncontrolled. This could result in plugging of the spray nozzles

and flow orifices. This aging mechanism and effect will apply since the spray nozzles and flow

orifices are occasionally wetted, even though the majority of the time this system is on standby.

The wetting and drying of these components can accelerate corrosion and fouling. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is

adequately managed.

The staff confirmed that the spray nozzles are copper alloy, and that there are no steel orifices

in drywell and suppression chamber spray systems exposed to an indoor air environment

(internal) in the ESF systems at JAFNPP. On the basis that JAFNPP does not have any

components subject to this aging effect, the staff finds that this aging effect does not require

management at JAFNPP.

The staff recognizes that, per industry operating experience, corrosion products in piping

upstream of the spray system nozzles can dislodge and cause blockage of the nozzles.

During the audit and review, the staff asked the applicant if this has been experienced at

JAFNPP and how it will be managed.

In its response, the applicant stated that surveillance testing is performed at JAFNPP to ensure

that the drywell and suppression chamber spray nozzles are unobstructed by aligning service

air to each of the spray headers and verifying air flow from each spray nozzle. This is

performed every 10 years in accordance with the JAFNPP ISI Program. In past surveillance

tests, some nozzle blockage was detected; however, it was below the acceptance criteria and

was successfully removed. Continued surveillance testing during the period of extended

operation will ensure that blockage does not impact nozzle flow capability. The staff considers

the applicant's Inservice Inspection testing to be adequate to ensure that spray system nozzle

flow capability is maintained during the period of extended operation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.7. For those line items that apply to LRA Section 3.2.2.2.7,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion

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The staff reviewed LRA Section 3.2.2.2.8 against the SRP-LR Section 3.2.2.2.8 criteria.

(1) In LRA Section 3.2.2.2.8, Item 1, the applicant addressed loss of material due to

general, pitting, and crevice corrosion for BWR steel piping, piping components, and

piping elements exposed to treated water. The applicant stated that this aging effect is

managed by the Water Chemistry Control - BWR Program. The effectiveness of the

Water Chemistry Control - BWR Program will be confirmed by the One-Time Inspection

Program through an inspection of a representative sample of components crediting this

Program including susceptible locations such as areas of stagnant flow. The Periodic

Surveillance and Preventive Maintenance Program supplements the Water Chemistry

Control - BWR Program for components at the waterline in the suppression chamber

and for components subject to erosion.

SRP-LR Section 3.2.2.2.8, Item 1, states that loss of material due to general, pitting,

and crevice corrosion could occur for BWR steel piping, piping components, and piping

elements exposed to treated water. The existing AMP relies on monitoring and control of

water chemistry for BWRs to mitigate degradation. However, control of water chemistry

does not preclude loss of material due to general, pitting, and crevice corrosion at

locations of stagnant flow conditions. Therefore, the effectiveness of the chemistry

control program should be verified to ensure that corrosion is not occurring. The GALL

Report recommends further evaluation of programs to verify the effectiveness of the

water chemistry control program. A one-time inspection of select components at

susceptible locations is an acceptable method to determine whether an aging effect is

not occurring or an aging effect is progressing Very slowly such that the component's

intended function will be maintained during the period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in GALL

Report, and are adequate to manage loss of material due to general, pitting, and crevice

corrosion for BWR steel piping, piping components, and piping elements exposed to

treated water. The staff finds that AMRs crediting these two programs are acceptable.

With regard to the applicant's use of the Periodic Surveillance and Preventive

Maintenance Program, the staff asked the applicant, during the audit and review, to

clarify whether this program is in addition to the one-time inspection or whether it

replaces the one-time inspection to verify the effectiveness of the Water Chemistry

Control Program. In its response, the applicant stated that the Periodic Surveillance and

Preventive Maintenance Program replaces the one-time inspection for management of

components at the waterline in the suppression chamber that are not continuously

wetted. The Periodic Surveillance and Preventive Maintenance Program is credited for

these components since a periodic inspection is needed to monitor aging of these

components. The staff reviewed the applicant's Periodic Surveillance and Preventive

Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4. The

staff determined that it includes periodic inspections that are consistent with a one-time

inspection and will be effective to verify the effectiveness of the water chemistry

program for components at the waterline in the suppression chamber. The staff

concluded that a periodic inspection is appropriate for these components since they are

intermittently wetted, which could make them more susceptible to degradation. On this

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basis, the staff finds that the applicant has met the criteria of SRP-LR Section 3.2.2.2.8,

Item 1 for further evaluation.

(2) In LRA Section 3.2.2.2.8, Item 2, the applicant addressed loss of material due to

general, pitting, and crevice corrosion for the internal surfaces of steel containment

isolation piping, piping components, and piping elements exposed to treated water. The

applicant stated that this aging effect is managed by the Water Chemistry Control -

BWR Program. The effectiveness of the Water Chemistry Control - BWR Program will

be confirmed by the One-Time Inspection Program through an inspection of a

representative sample of components crediting this program including susceptible

locations such as areas of stagnant flow.

SRP-LR Section 3.2.2.2.8, Item 2, states that loss of material due to general, pitting,

and crevice corrosion could occur for the internal surfaces of steel containment isolation

piping, piping components, and piping elements exposed to treated water. The existing

AMP relies on monitoring and control of water chemistry to mitigate degradation.

However, control of water chemistry does not preclude loss of material due to general,

pitting, and crevice corrosion at locations of stagnant flow conditions. Therefore, the

effectiveness of the water chemistry control program should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to verify the effectiveness of the Chemistry Control Program. A one-time

inspection of select components at susceptible locations is an acceptable method to

determine whether an aging effect is not occurring or an aging effect is progressing very

slowly such that the component's intended function will be maintained during the period

of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in GALL

Report, and are adequate to manage loss of material due to general, pitting, and crevice

corrosion for the internal surfaces of steel containment isolation piping, piping

components, and piping elements exposed to treated water. On this basis, the staff

finds that the applicant has met the criteria of SRP-LR Section 3.2.2.2.8, Item 2, for

further evaluation.

(3) In LRA Section 3.2.2.2.8, Item 3, the applicant addressed loss of material due to

general, pitting, and crevice corrosion for steel piping, piping components, and piping

elements exposed to lubricating oil. The applicant stated that this aging effect is

managed by the Oil Analysis Program. This program includes periodic sampling and

analysis of lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment that is not conducive to corrosion. During the past five years,

many visual inspections of components containing lubricating oil have been performed

during corrective and preventive maintenance activities. The visual inspections of these

components would identify degraded conditions such as fouling, corrosion or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one-time inspection to provide confirmation of the

effectiveness of the Oil Analysis Program.

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SRP-LR Section 3.2.2.2.8, Item 3, states that loss of material due to general, pitting,

and crevice corrosion could occur for steel piping, piping components, and piping

elements exposed to lubricating oil. The existing program relies on the periodic sampling

and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment that is not conducive to corrosion. However, control of lube

oil contaminants may not always have been adequate to preclude corrosion. Therefore,

the effectiveness of lubricating oil control should be verified to ensure that corrosion is

not occurring. The GALL Report recommends further evaluation to verify the

effectiveness of the lubricating oil program. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the

period of extended operation.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is

documented in SER Section 3.0.3.2.14. The staff determined that this program includes

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits. The staff finds that these activities are consistent with the

recommendations in GALL Report, and are adequate to manage loss of material due to

general, pitting, and crevice corrosion for steel piping, piping components, and piping

elements exposed to lubricating oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP. In its response, the

applicant stated that the LRA will be amended to add activities to confirm the

effectiveness of the Oil Analysis Program to the One-Time Inspection AMP. In its

response dated February 1, 2007, the applicant amended the LRA Section 3.2.2.2.8,

Item 3, to state "One-time Inspection Program activities will be utilized to confirm the

effectiveness of the Oil Analysis Program." The staff finds that the use of a one-time

inspection to verify the effectiveness of the oil analysis program is consistent with the

recommendations in GALL Report, and is acceptable. On this basis, the staff finds that

the applicant has met the criteria of SRP-LR Section 3.2.2.2.8, Item 3, for further

evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.8. For those line items that apply to LRA Section 3.2.2.2.8,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9.

In LRA Section 3.2.2.2.9, the applicant addressed loss of material due to general, pitting,

crevice, and MIC for steel (with or without coating or wrapping) piping, piping components, and

piping elements buried in soil. The applicant stated that this aging effect is managed by the

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Buried Piping and Tanks Inspection Program, which will include (a) preventive measures to

mitigate corrosion and (b) inspections to manage the effects of corrosion on the

pressure-retaining capability of buried carbon steel components. Buried components will be

inspected when excavated during maintenance. An inspection will be performed within

ten years of entering the period of extended operation, unless an opportunistic inspection

occurred within this ten-year period.

SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC

could occur for steel (with or without coating or wrapping) piping, piping components, and piping

elements buried in soil. The buried piping and tanks inspection program relies on industry

practice, frequency of pipe excavation, and operating experience to manage the effects of loss

of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried

piping and tanks inspection program should be verified to evaluate an applicant's inspection

frequency and operating experience with buried components, ensuring that loss of material is

not occurring.

The staff reviewed the applicant's Buried Piping and Tanks Inspection Program and its

evaluations are documented in SER Section 3.0.3.2.1. The staff determined that this program

include opportunistic or focused inspections of buried components that are consistent with the

recommendations in GALL Report, and are adequate to manage loss of material due to

general, pitting, crevice, and MIC for steel (with or without coating or wrapping) piping, piping

components, and piping elements buried in soil. The staff confirmed that inspections will be

performed both during the 10-year period immediately prior to the period of extended operation,

as well as during the 10-year period after entering the period of extended operation, which is

consistent with the recommendations in GALL Report.

During the audit and review, the staff also asked the applicant for additional information on

JAFNPP operating experience with buried components.

In its response, the applicant stated that a search of condition reports from the early 1990s to

present identified only one incident in which a leak in a buried hydrogen supply line was

evaluated. The root cause was determined to be poor application of the protective coating on

the line, and was not aging related. Corrective actions were taken to replace the degraded

section of buried piping. The staff reviewed the CR and determined that this incident was not

age-related. In addition, the applicant stated that during the period from the mid 1990s to

present, several fire protection system buried valves were excavated and none showed any

evidence of corrosion. Based on a review of JAFNPP plant-specific operating experience, the

staff confirmed that opportunistic inspections of buried components are performed at JAFNPP,

and loss of material on buried components that would lead to a loss of intended function is not

occurring. The staff finds that the JAFNPP operating experience supports the use of the Buried

Piping and Tanks Inspection Program as an effective means of managing aging of buried

components. On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.9 for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.2.2.2.9. For those line items that apply to LRA Section 3.2.2.2.9,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

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required by 10 CFR 54.21(a)(3).

3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for

which the applicant has claimed consistency with the GALL Report and for which the GALL

Report recommends further evaluation, the staff determined that the applicant has adequately

addressed the issues recommended for further evaluated. 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 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-7,

3.3.2-14-1 through 3.3.2-14-4, 3.3.2-14-7, 3.3.2-14-8, 3.3.2-14-10, and 3.3.2-14-14 the staff

reviewed additional details concerning the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information concerning how the

aging effects will be managed. Specifically, note F indicates that the material for the AMR line

item component is not evaluated in the GALL Report. Note G indicates that the environment for

the AMR line item component and material is not evaluated in the GALL Report. Note H

indicates that the aging effect for the AMR line item component, material, and environment

combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified

in the GALL Report for the line item component, material, and environment combination is not

applicable. Note J indicates that neither the component nor the material and environment

combination for the line item is evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

3.2.2.3.1 Residual Heat Removal System Summary of Aging Management Evaluation -

LRA Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the

residual heat removal system component groups.

The staff noted that LRA Table 3.2.2-1 includes an AMR line-item to address copper alloy

nozzles in the Residual Heat Removal system exposed to air-indoor uncontrolled (external).

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The AMR line states that there are no aging mechanisms or effects for these

material/environment combinations. The AMR line cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff noted that the GALL Report does address other components constructed of copper

alloy that are exposed to air, indoor-uncontrolled for which no aging effect is noted (e.g.,

Item EP-10 in Table V.F). In addition, based on industry operating experience, the staff

recognizes that this material/environment combination is not susceptible to significant aging

degradation. The staff reviewed the JAFNPP plant-specific operating experience with

components in the ESF systems containing this material/environment combination and

confirmed that no aging effects have been experienced. On this basis, the staff finds the AMR

results for this line item acceptable.

The staff noted that LRA Table 3.2.2-1 includes an AMR line-item to address Heat Exchanger

(tubes) in the Residual Heat Removal Systems constructed of stainless steel and exposed to

treated water >1400F. The Service Water Integrity Program is credited to manage loss of

material-wear. The AMR line cites Generic Note H, which indicates that this aging effect is not

in GALL Report for this component, material and environment combination.

During the audit and review, the staff asked the applicant to clarify why the Service Water

Integrity Program, which addresses components exposed to service water, is credited for this

AMR instead of a water chemistry AMP.

In its response, the applicant stated these heat exchangers are cooled by the service water

system. Although the aging effect being managed is loss of material due to wear on the

external tube surface, which is exposed to treated water, eddy current testing performed as part

of the service water integrity program is more appropriate to detect loss of material for the

tubes. The staff determined that eddy current testing is more appropriate for detecting and

managing loss of material for the heat exchanger tubes since it can detect wall thinning. On this

basis, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.2 Core Spray System Summary of Aging Management Evaluation - LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the

core spray system component groups, and determined that the applicant did not include any

AMR results with Generic Notes F through J involving material, environment, AERMs, and AMP

combinations that are not evaluated in the GALL Report.

3.2.2.3.3 Automatic Depressurization System Summary of Aging Management Evaluation -

LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the

automatic depressurization system component groups. The staff noted that LRA Table 3.2.2-3

includes an AMR line item for a "T-quencher" constructed of stainless steel and exposed to

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steam (internal). The AMR line states that cracking-fatigue of this component is managed as a

TLAA - metal fatigue. The AMR line cites Generic Note G, which indicates that this environment

is not in GALL Report for this component and material combination. TLAAs are evaluated in

SER Section 4.3.

3.2.2.3.4 High Pressure Coolant Injection System Summary of Aging Management

Evaluation - LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the

high pressure coolant injection system component groups.

The staff noted that LRA Table 3.2.2-4 includes AMR line items to address stainless steel

orifice, rupture disk and-valve body exposed to air-indoor uncontrolled,(internal). The AMR

results state that there are no aging mechanisms or effects for these material/ environment

combinations. The AMR lines cite Generic Note G, which indicates that the environment is not

addressed in GALL Report for this component and material combination. The staff noted that

the GALL Report does address other components constructed of stainless steel that are

exposed to air, indoor-uncontrolled for which no aging effect is noted (e.g., Item EP-18 in

Table V.F). In addition, based on industry operating experience, the staff recognizes that this

material/environment combination is not susceptible to significant aging degradation. The staff

reviewed the JAFNPP plant-specific operating experience with components in the ESF systems

containing this material/environment combination and confirmed that no aging effects that

would lead to the loss of intended function have been experienced. On this basis, the staff finds

the AMR results for these line items acceptable.

The staff noted that LRA Table 3.2.2-4 includes AMR line items for stainless steel orifice,

rupture disk and tubing exposed to steam (internal). The AMR results state that cracking-fatigue

of these components is managed as a TLAA - metal fatigue. The AMR line items cite Generic

Note G, which indicates that this environment is not in GALL Report for this component and

material combination. TLAAs are evaluated in SER Section 4.3.

The staff noted that LRA Table 3.2.2-4 includes an AMR line item to address copper alloy heat

exchanger tubes exposed to lubricating oil (external). The AMR line item credits the Heat

Exchanger Monitoring Program to manage loss of material-wear for these components. The

AMR line item cites Generic Note H, which indicates that this aging effect is not addressed in

GALL Report for this component, material, and environment combination. The staff reviewed

the applicant's Heat Exchanger Monitoring Program and determined that this program includes

eddy current testing of a representative sample of heat exchanger tubes to detect aging

degradation. If degradation is found, an evaluation is performed to determine if corrective

actions are necessary. The staff finds that these activities are adequate to manage loss of

material-wear for heat exchanger tubes exposed to lubricating oil in the ESF systems since

eddy current testing is a proven technique to detect wall thinning in tubes. The staff's review

and evaluation of the applicant's Heat Exchanger Monitoring Program are documented in SER

Section 3.0.3.3.1. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.2.2-4 includes an AMR line item to address copper alloy heat

exchanger tubes exposed to treated water (external). The AMR line item credits the Heat

Exchanger Monitoring Program to manage loss of material-wear for these components. The

AMR line item cites Generic Note H, which indicates that this aging effect is not addressed in

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GALL Report for this component, material, and environment combination. The staff reviewed

the applicant's Heat Exchanger Monitoring Program and determined that this program includes

eddy current testing of a representative sample of heat exchanger tubes to detect aging

degradation. If degradation is found, an evaluation is performed to determine if corrective

actions are necessary. The staff finds that these activities are adequate to manage loss of

material-wear for heat exchanger tubes exposed to treated water in the ESF systems since

eddy current testing is a proven technique to detect wall thinning in tubes. The staff's review

and evaluation of the applicant's Heat Exchanger monitoring Program are documented in SER

Section 3.0.3.3.1. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.2.2-4 includes an AMR line item to address stainless steel

valve bodies exposed to lubricating oil (internal). The AMR line item credits the Oil Analysis

Program to manage cracking for these components. The AMR line item cites Generic Note H,

which indicates that this aging effect is not addressed in GALL Report for this component,

material, and environment combination. The staff reviewed the applicant's Oil Analysis Program

and its evaluations are documented in SER Section 3.0.3.2.14. The staff determined that this

program includes periodic oil sampling and analysis to preserve an environment that is not

conducive to cracking. In addition, the applicant will amend the LRA to include a one-time

inspection to verify the effectiveness of the oil analysis program (See SER Section 3.2.2.2). The

staff finds that these activities are adequate to manage cracking for valve bodies exposed to

lubricating oil in the ESF systems since maintaining an acceptable level of lube oil purity

provides an environment that is not conducive to cracking. This will be verified by a one-time

inspection. On this basis, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 Reactor Core Isolation Cooling Summary of Aging Management Evaluation -

LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the

reactor core isolation cooling component groups.

The staff noted that LRA Table 3.2.2-5 includes an AMR line item to address stainless steel

piping exposed to air-outdoor (external). The AMR line item credits the External Surfaces

Monitoring Program to manage loss of material for these components. The AMR line item cites

Generic Note G, which indicates that the environment is not addressed in GALL Report for this

component and material combination. The staff reviewed the applicant's External Surfaces

Monitoring Program and its evaluations are documented in SER Section 3.0.3.2.9. The staff

determined that this program includes periodic inspections of component external surfaces to

detect aging degradation. The staff also determined that these activities are adequate to

manage loss of material for stainless steel piping exposed to air-outdoor. On this basis, the

staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3..2.2-5 includes AMR line items for stainless steel orifice,

thermowell, tubing, and valve bodies exposed to steam (internal). The AMR line items state that

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cracking-fatigue of these components is managed as a TLAA - metal fatigue. The AMR line

items cite Generic Note G, which indicates that this environment is not in the GALL Report for

this component and material combination. TLAAs are evaluated in SER Section 4.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.6 Standby Gas Treatment System Summary of Aging Management Evaluation -

LRA Table 3.2.2-6

The-staff reviewed LRA Table 3.2.2-6, which summarizes the resultsi of AMR evaluations for the

standby gas treatment system component groups. The staff noted that LRA Table 3.2.2-6

includes AMR line items to address copper alloy tubing, glass sight glasses, stainless steel flow

elements, and stainless steel tubing exposed to air-indoor uncontrolled (internal). The AMR line

items state that there are no aging mechanisms or effects for these material/environment

combinations. The AMR line items cite Generic Note G, which indicates that the environment is

not addressed in GALL Report for these component and material combinations. The staff noted

that the GALL Report does address other components constructed of copper alloy, glass, and

stainless steel that are exposed to air, indoor-uncontrolled for which no aging effect is noted

(e.g., Item EP-10, EP-15, and EP-18 in Table V.F, respectively). Based on industry operating

experience, the staff recognizes that these material/environment combinations are not

susceptible to significant aging degradation. The staff reviewed the JAFNPP plant-specific

operating experience with components in the ESF systems containing these

material/environment combinations and confirmed that no aging effects that would lead to the

loss of intended function have been experienced. On this basis, the staff finds the AMR results

for these line items acceptable.

The staff noted that LRA Table 3.2.2-6 includes an AMR line item to address copper alloy

piping exposed to soil (external). The AMR line item credits the Buried Piping and Tanks

Inspection program to manage loss of material for these components. The AMR line item cites

Generic Note G, which indicates that the environment is not addressed in GALL Report for this

component and material combination. The staff reviewed the applicant's Buried Piping and

Tanks Inspection Program and determined that this program includes opportunistic or focused

inspections of buried components to detect degradation. The staff finds that these activities are

adequate to manage loss of material for copper alloy piping buried in soil. The staff confirmed

that inspections will be performed both during the 10-year period immediately prior to the period

of extended operation, as well as during the 10-year period after entering the period of

extended operation. The staff also reviewed JAFNPP plant-specific operating experience and

confirmed that loss of material on buried components that would lead to a loss of intended

function during the period of extended operation is not occurring. On this basis, the staff finds

the AMR results for this line item acceptable.

The staff noted that LRA Table 3.2.2-6 includes an AMR line item for stainless steel tubing

exposed to steam (internal). The AMR line item states that cracking-fatigue of these

components is managed as a TLAA - metal fatigue. The AMR line item cites Generic Note G,

which indicates that this environment is not in the GALL Report for this component and material

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combination. TLAAs are evaluated in SER Section 4.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.2.2.3.7 Primary Containment Penetrations Summary of Aging Management Evaluation -

LRA Table 3.2.2-7

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the

primary containment penetrations component groups. The staff noted that LRA Table 3.2.2-7

includes AMR line items to address stainless steel piping, tubing, and valve bodies exposed to

air-indoor uncontrolled (internal). The AMR line items state that there are no aging mechanisms

or effects for these material/ environment combinations. The AMR line items cite Generic

Note G, which indicates that the environment is not addressed in GALL Report for this

component and material combination. The staff noted that the GALL Report does address other

components constructed of stainless steel that are exposed to air, indoor-uncontrolled for which

no aging effect is noted (e.g., Item EP-18 in Table V.F). Based on industry operating

experience, the staff recognizes that this material/environment combination is not susceptible to

significant aging degradation. The staff reviewed the JAFNPP plant-specific operating

experience with components in the ESF systems containing this material/environment

combination and confirmed that no aging effects that would lead to the loss of intended function

have been experienced. On this basis, the staff finds the AMR results for these line items

acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.8 Gas Handling System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-1

The staff reviewed LRA Table 3.3.2-14-1, which summarizes the results of AMR evaluations for

the gas handling system component groups.

The staff noted that LRA Table 3.2.2-14-1 includes an AMR line item for stainless steel tubing

exposed to steam (internal). The AMR line item states that cracking-fatigue of these

components is managed as a TLAA - metal fatigue. The AMR line item cites Generic Note G,

which indicates that this environment is not in GALL Report for this component and material

combination. TLAAs are evaluated in SER Section 4.3.

3.2.2.3.9 Reactor Coolant System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-2

The staff reviewed LRA Table 3.3.2-14-2, which summarizes the results of AMR evaluations for

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the reactor coolant system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.2.2.3.10 Control Rod Drive System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-3

The staff reviewed LRA Table 3.3.2-14-3, which summarizes the results of AMR evaluations for

the control rod drive system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.2.2.3.11 Residual Heat Removal System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation .- LRA Table 3.3.2-14-4

The staff reviewed LRA Table 3.3.2-14-4, which summarizes the results of AMR evaluations for

the residual heat removal system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.2.2.3.12 -Reactor Core Isolation Cooling System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-7

The staff reviewed LRA Table 3.3.2-14-7, which summarizes the results of AMR evaluations for

the reactor core isolation cooling system component groups.

The staff noted that LRA Table 3.2.2-14-7 includes an AMR line item for stainless steel valve

bodies exposed to steam (internal). The AMR line item states that cracking-fatigue of these

components is managed as a TLAA - metal fatigue. The AMR line item cites Generic Note G,

which indicates that this environment is not in GALL Report for this component and material

combination. TLAAs are evaluated in SER Section 4.3.

3.2.2.3.13 Core Spray System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-8

The staff reviewed LRA Table 3.3.2-14-8, which summarizes the results of AMR evaluations for

the core spray system component groups, and determined that the applicant did not include any

AMR results with Generic Notes F through J involving material, environment, AERMs, and AMP

combinations that are not evaluated in the GALL Report.

3.2.2.3.14 Primary Containment System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-10

The staff reviewed LRA Table 3.3.2-14-10, which summarizes the results of AMR evaluations

for the primary containment system component groups.

The staff noted that LRA Table 3.2.2-14-10 includes an AMR line item to address copper alloy

tubing exposed to air-indoor (internal). The AMR line item states that there are no aging

mechanisms or effects for this material/environment combination. The AMR line item cites

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Generic Note H, which indicates that the aging effect is not addressed in GALL Report for this

component, material, environment combination. Based on industry operating experience, the

staff recognizes that this material/environment combination is not susceptible to significant

aging degradation. The staff reviewed the JAFNPP plant-specific operating experience with

components in the ESFsystems containing this material/environment combination and

confirmed that no aging effects that would lead to the loss of intended function during the

period of extended operation have been experienced. On this basis, the staff finds the AMR

results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.2.2.3.15 High Pressure Coolant Injection System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-14

The staff reviewed LRA Table 3.3.2-14-14, which summarizes the results of AMR evaluations

for the high pressure coolant injection system component groups.

The staff noted that LRA Table 3.2.2-14-14 includes an AMR line item for stainless tubing

exposed to steam (internal). The AMR line item states that cracking-fatigue of these

components is managed as a TLAA - metal fatigue. The AMR line item cites Generic Note G,

which indicates that this environment is not in the GALL Report for this component and material

combination. TLAAs are evaluated in SER Section 4.3.

Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated

the AMR results involving material, environment, AERMs, 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 engineered safety features systems components, that are within the

scope of license renewal and subject to an AMR, will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups of the following:

* standby liquid control

* service water

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* emergency diesel generator

* fuel oil

* fire protection-water

* fire protection-CO 2

* heating, ventilation, and air conditioning

* containment purge, containment atmosphere dilution, and post-accident sampling

* fuel pool cooling and cleanup

* service, instrument, and breathing air

* reactor building closed loop cooling water

* radwaste and plant drains

* security generator

* miscellaneous systems in-scope for 10 CFR 54.4(a)(2)

3.3.1 Summary of Technical Information in the Application

In LRA Section 3.3, the applicant provided AMR results for the auxiliary systems components

and component groups. In LRA Table 3.3.1, "Summary of Aging Management Programs for the

Auxiliary Systems Evaluated in Chapter VII of NUREG-1 801," the applicant provided a

summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the auxiliary

systems components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of 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, that

are 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 confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.3.2.1.

In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.3.2.2. The staff's

audit evaluations are documented in SER Section 3.3.2.2.

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In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

effects listed were appropriate for the combination of materials and environments specified. The

staffs audit evaluations are documented in SER Section 3.3.2.3. The staff's evaluation of the

technical review is also documented in SER Section 3.3.2.3.

The staff noted that the applicant has included all the 44 miscellaneous systems within the

scope of 10 CFR 54.4(a)(2) in Section 3.3, "Auxiliary Systems," Tables 3.3.2-14-1 through

3.3.2-14-44. However, 8 of these systems are ESF systems and should have been included in

Section 3.2, and 10 of these systems are in steam and power conversion (S&PC) systems and

should have been included in Section 3.4. The Table 2s that apply to these 18 systems do

reference Table 3.2. 1 and Table 3.4.1 line items in the Table 1 line item reference column. This

SER preparation is based on systems as defined in SRP-LR, Section 3.2, "ESF Systems,"

Section 3.3, "Auxiliary Systems," and Section 3.4, "S&PC Systems."

During the audit and review, the staff asked the applicant to justify why the nonsafety-related

systems associated with ESF and S&PC systems were included in the auxiliary systems

section.

In its response, the applicant stated that Section 14 (miscellaneous systems) includes all

systems that have intended functions that meet 10 CFR 54.4(a)(2) for physical interaction. The

aging management review of these systems was presented separately from the review of

systems with intended functions that met 10 CFR 54.4(a)(1) or (a)(3) so that they could be

reviewed separately on the basis of physical proximity rather than system function. This allows

a reviewer to clearly distinguish which component types in a system were included for

10 CFR 54.4(a)(2) for physical interaction. Since most of these systems are auxiliary systems,

they were added as part of the auxiliary systems section.

The staff reviewed the applicant's response and determined that this approach to presenting

the AMRs for systems with intended functions meeting 10 CFR 54.4(a)(2) for physical

interaction impedes the review process rather than facilitating it since the SER preparation is

based on systems as defined in SRP-LR, which includes six specific sections. Each reviewer

focuses on a specific section, and all of the systems included in that section. Therefore, the

approach used in this LRA makes the review more cumbersome since the reviewers must also

review Section 3 on auxiliary systems to ensure that all systems in their scope are addressed.

However, the staff determined that this approach is administrative in nature, and does not

impact the technical accuracy of these AMRs. Therefore, the staff finds this approach

acceptable. The SER will split these tables and include them in their respective sections as

follows:

" Section 3.2 - Tables 3.3.2-14-1, 2, 3, 4, 7, 8, 10, and 14

" Section 3.3 - Tables 3.3.2-14-5, 6, 9, 11, 12,13, 15, 18, 23 to 41, and 43

* Section 3.4-Tables 3.3.2-14-16, 17, 19, 20, 21, 22, 42, and 44

3-246
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the auxiliary systems components.

Table 3.3-1, provided below, includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.3, that are addressed in the GALL

Report.

Table 3.3-1 Staff Evaluation for Auxiliary Systems in the GALL Report

Component Group Aging Effect/ AMP In GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.) _

Steel cranes - Cumulative fatigue TLAA to be Not used Consistent with

structural girders damage evaluated for GALL Report, which

exposed to air - structural girders of recommends further

indoor uncontrolled cranes. See the evaluation (See

(external) Standard Review SER

(3.3.1-1) Plan, Section 4.7 for Section 3.3.2.2.1)

generic guidance

for meeting the

requirements of

10 CFR 54.21(c)(1).

Steel and stainless Cumulative fatigue TLAA, evaluated in TLAA Consistent with

steel piping, piping damage accordance with GALL Report, which

components, piping 10 CFR 54.21(c) recommends further

elements, and heat evaluation (See

exchanger SER

components Section 3.3.2.2.1)

exposed to air -

indoor uncontrolled,

treated borated

water or treated

water

(3.3.1 ,2)

Stainless steel heat Reduction of heat Water Chemistry Not Applicable Not applicable (See

exchanger tubes transfer due to and One-Time SER

exposed to treated fouling Inspection Section 3.3.2.2.2)

water

(3.3.1-3)

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable (See

piping, piping stress corrosion and One-Time SER

components, and cracking Inspection Section 3.3.2.2.3,

piping elements Item 1)

exposed to sodium

pentaborate

solution > 60'C

(> 140'F)

(3.3.1-4)

3-247
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to A plant-specific Water Chemistry Consistent with

stainless clad steel stress corrosion aging management Control-BWR GALL Report, which

heat exchanger cracking program is to be (B.1.29.2) and recommends further

components evaluated. One-Time evaluation (See

exposed to treated Inspection (B.1.21) SER

water > 60'C Section 3.3.2.2.3,

(> 140'F) Item 2)

(3.3.1-5)

Stainless steel Cracking due to A plant-specific Periodic Consistent with

diesel engine stress corrosion aging management Surveillance and GALL Report, which

exhaust piping, cracking program is to be Preventive recommends further

piping components, evaluated. Maintenance evaluation (See

and piping elements (B.1.22) SER

exposed to diesel Section 3.3.2.2.3,

exhaust Item 3)

(3.3.1-6)

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable to

non-regenerative stress corrosion and a plant-specific BWRs (See SER

heat exchanger cracking and cyclic verification Section 3.3.2.2.4,

components loading program. An Item 1)

exposed to treated acceptable

borated water verification program

> 601C (> 140 0F) is to include

(3.3.1-7) temperature and

radioactivity

monitoring of the

shell side water,

and eddy current

testing of tubes.

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable to

regenerative heat stress corrosion and a plant-specific BWRs (See SER

exchanger cracking and cyclic verification Section 3.3.2.2.4,

components loading program. The AMP Item 2)

exposed to treated is to be augmented

borated water by verifying the

> 60 0C (> 140 0 F) absence of cracking

(3.3.1-8) due to stress

corrosion cracking

and cyclic loading.

A plant-specific

aging management

program is to be

evaluated.

3-248
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Cracking due to Water Chemistry Not Applicable Not applicable to

high-pressure pump stress corrosion and a plant-specific BWRs (See SER

casing in PWR cracking and cyclic verification Section 3.3.2.2.4,

chemical and loading program. The AMP Item 3)

volume control is to be augmented

system by verifying the

(3.3.1-9) absence of cracking

due to stress

corrosion cracking

and cyclic loading.

A plant-specific

aging management

program is to be

evaluated,

High-strength steel Cracking due to Bolting Integrity Not Applicable Not applicable (See

closure bolting stress corrosion The AMP is to be SER

exposed to air with cracking, cyclic augmented by Section 3.3.2.2.4,

steam or water loading appropriate Item 4)

leakage. inspection to detect

(3.3.1-10) cracking if the bolts

are not otherwise

replaced during

maintenance.

Elastomer seals Hardening and loss A plant-specific Periodic Consistent with

and components of strength due to aging management Surveillance and GALL Report, which

exposed to air - elastomer program is to be Preventive recommends further

indoor uncontrolled degradation evaluated Maintenance evaluation (See

(intemal/extemal) (B.1.22) SER

(3.3.1-11) Section 3.3.2.2.5,

Item 1)

Elastomer lining Hardening and loss A plant-specific Not Applicable Not applicable (See

exposed to treated of strength due to aging management SER

water or treated elastomer program is to be Section 3.3.2.2.5,

borated water degradation evaluated. Item 2)

(3.3.1-12)

Boral, boron steel Reduction of A plant-specific Water Chemistry Consistent with

spent fuel storage neutron-absorbing aging management Control-BWR GALL Report, which

racks capacity and loss of program is to be (B.1.29.2) recommends further

neutron-absorbing material due to evaluated evaluation (See

sheets exposed to general corrosion SER

treated water or Section 3.3.2.2.6)

treated borated

water

(3.3.1-13)

Steel piping, piping Loss of material Lubricating Oil Oil Analysis Consistent with

component, and due to general, Analysis and (B.1.20) and GALL Report, which

piping elements pitting, and crevice One-Time One-Time recommends further

exposed to corrosion Inspection Inspection (B.1.21) evaluation (See

lubricating oil SER

(3.3.1-14) Section 3.3.2.2.7,

Item 1)

3-249
Component Group Aging Effect/ AMP In GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel reactor Loss of material Lubricating Oil Not Applicable Not applicable (See

coolant pump oil due to general, Analysis and SER

collection system pitting, and crevice One-Time Section 3.3.2.2.7,

piping, tubing, and corrosion Inspection Item 1)

valve bodies

exposed to

lubricating oil

(3.3.1-15)

Steel reactor Loss of material Lubricating Oil Not Applicable Not applicable (See

coolant pump oil, due to general, Analysis and SER

collection system pitting, and crevice One-Time Section 3.3.2.2.7,

tank exposed to corrosion Inspection to Item 1)

lubricating oil evaluate the

(3.3.1-16) thickness of the

lower portion of the

tank

Steel piping, piping Loss of material Water Chemistry Water Chemistry Consistent with

components, and due to general, and One-Time Control-BWR GALL Report, which

piping elements pitting, and crevice Inspection (B.1.29.2) and recommends further

exposed to treated corrosion One-Time evaluation (See

water Inspection (B.1.21) SER

(3.3.1-17) Section 3.3.2.2.7,

Item 2)

Stainless steel and Loss of A plant-specific Periodic Consistent with

steel diesel engine material/general aging management Surveillance and GALL Report, which

exhaust piping, (steel only), pitting program is to be Preventive recommends further

piping components, and crevice evaluated Maintenance evaluation (See

and piping elements corrosion (B.1.22) or Fire SER

exposed to diesel Protection Section 3.3.2.2.7,

exhaust (B.1.13.1) Item 3)

(3.3.1-18)

Steel (with or Loss of material Buried Piping and Buried Piping and Consistent with

without coating or due to general, Tanks Surveillance Tanks Inspection GALL Report, which

wrapping) piping, pitting, crevice, and (B.1.1) recommends further

piping components, microbiologically or evaluation (See

and piping elements influenced corrosion SER

exposed to soil Buried Piping and Section 3.3.2.2.8)

(3.3.1-19) Tanks Inspection

Steel piping, piping Loss of material Fuel Oil Chemistry Diesel Fuel Consistent with

components, piping due to general, and One-Time Monitoring (B.1.9) GALL Report, which

elements, and tanks pitting, crevice, and Inspection recommends further

exposed to fuel oil microbiologically evaluation (See

(3.3.1-20) influenced SER

corrosion, and Section 3.3.2.2.9,

fouling Item 1)

3-250
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel heat Loss of material Lubricating Oil Oil Analysis Consistent with

exchanger due to general, Analysis and (B.1.20) and GALL Report, which

components pitting, crevice, and One-Time One-Time recommends further

exposed to microbiologically Inspection Inspection (8.1.21) evaluation (See

lubricating oil influenced SER

(3.3.1-21) corrosion, and Section 3.3.2.2.9,

fouling Item 2)

Steel with elastomer Loss of material . Water Chemistry Not Applicable Not applicable (See

lining or stainless due to pitting and and One-Time SER.

steel cladding crevice corrosion Inspection Section 3.3.2.2.10,

piping, piping (only for steel after Item 1 )

:components, and. lining/cladding

piping elements degradation)

exposed to treated

water and treated

borated water

(3.3.1-22)

Stainless steel and Loss of material Water Chemistry Water Chemistry Consistent with

steel with stainless due to pitting and and One-Time Control-BWR GALL Report, which

steel cladding heat crevice corrosion Inspection (B.1.29.2) and recommends further

exchanger One-Time evaluation (See

components Inspection (8.1.21) SER

exposed to treated Section 3.3.2.2.10,

water Item 2)

(3.3.1-23)

Stainless steel and Loss of material Water Chemistry Water Chemistry Consistent with

aluminum piping, due to pitting and and One-Time Control-BWR GALL Report, which

piping components, crevice corrosion Inspection (B.1.29.2) and recommends further

and piping elements One-Time evaluation (See

exposed to treated Inspection (B.1.21) SER

water Section 3.3.2.2.10,

(3.3.1-24) Item 2)

Copper alloy HVAC Loss of material A plant-specific External Surfaces Consistent with

piping, piping due to pitting and aging management Monitoring (B.1.11), GALL Report, which

components, piping crevice corrosion program is to be Periodic recommends further

elements exposed evaluated. Surveillance and evaluation (See

to condensation Preventive SER

(external) Maintenance Section 3.3.2.2.10,

(3.3.1-25) (B.1.22), or Service Item 3)

Water Integrity

(8.1.26)

Copper alloy piping, Loss of material Lubricating Oil Oil Analysis Consistent with

piping components, due to pitting and Analysis and (B.1.20) and GALL Report, which

and piping elements crevice corrosion One-Time One-Time recommends further

exposed to Inspection Inspection (8.1.21) evaluation (See

lubricating oil SER

(3.3.1-26) Section 3.3.2.2.10,

Item 4)

3-251
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Loss of material A plant-specific Bolting Integrity Consistent with

HVAC ducting and due to pitting and aging management (B.1.30), External GALL Report, which

aluminum HVAC crevice corrosion program is to be Surfaces Monitoring recommends further

piping, piping evaluated. (B.1.11), Periodic evaluation (See

components and Surveillance and SER

piping elements Preventive Section 3.3.2.2.10,

exposed to Maintenance Item 5)

condensation (B.1.22), or Service

(3.3.1-27) Water Integrity

(B.1.26)

Copper alloy fire Loss of material A plant-specific Periodic Consistent with

protection piping! due to pitting and aging management Surveillance and GALL Report, which

piping components, crevice corrosion program is to be Preventive recommends further

and piping elements evaluated. Maintenance evaluation (See

exposed to (B.1.22), or SER

condensation One-Time Section 3.3.2.2.10,

(internal) Inspection (B.1.21) Item 6)

(3.3.1-28)

Stainless steel Loss of material A plant-specific Not Applicable Not applicable (See

piping, piping due to pitting and aging management SER

components, and crevice corrosion program is to be Section 3.3.2.2.10,

piping elements evaluated. Item 7)

exposed to soil

(3.3.1-29)

Stainless steel Loss of material Water Chemistry Water Chemistry Consistent with

piping, piping due to pitting and and One-Time Control-BWR GALL Report, which

components, and crevice corrosion Inspection (B.1.29.2) and recommends further

piping elements One-Time evaluation (See

exposed to sodium Inspection (B.1.21) SER

pentaborate Section 3.3.2.2.10,

solution Item 8)

(3.3.1-30)

Copper alloy piping, Loss of material Water Chemistry Water Chemistry Consistent with

piping components, due to pitting, and One-Time Control-BWR GALL Report, which

and piping elements crevice, and Inspection (B.1.29.2) and recommends further

exposed to treated galvanic corrosion One-Time evaluation (See

water Inspection (B.1.21) SER

(3.3.1-31) Section 3.3.2.2.11)

Stainless steel, Loss of material Fuel Oil Chemistry Diesel Fuel Consistent with

aluminum and due to pitting, and One-Time Monitoring (B.1.9) GALL Report, which

copper alloy piping, crevice, and Inspection recommends further

piping components, microbiologically evaluation (See

and piping elements influenced corrosion SER

exposed to fuel oil Section 3.3.2.2.12,

(3.3.1-32) Item 1)

3-252
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Loss of material Lubricating Oil Oil Analysis Consistent with

piping, piping due to pitting, Analysis and (B.1.20) and GALL Report, which

components, and crevice, and One-Time One-Time recommends further

piping elements microbiologically Inspection Inspection (B.1.21) evaluation (See

exposed to influenced corrosion SER

lubricating oil Section 3.3.2.2.12,

(3.3.1-33) Item 2)

Elastomer seals Loss of material A plant-specific Not Applicable Not applicable (See

and components due to Wear aging management SER

exposed to air - program is to be Section 3.3.2.2.13)

indoor uncontrolled evaluated.

(internal or external) -

(3.3.1-34)

Steel with stainless Loss of material A plant-specific Not Applicable Not applicable to

steel cladding pump due to cladding aging management BWRs (See SER

casing exposed to breach program is to be Section 3.3.2.2.14)

treated borated evaluated.

water

(3.3.1-35) Reference NRC

Information

Notice 94-63, "Boric

Acid Corrosion of

Charging Pump

Casings Caused by

Cladding Cracks."

Boraflex spent fuel Reduction of Boraflex Monitoring Not Applicable Not applicable (See

storage racks neutron-absorbing SER

neutron-absorbing capacity due to Section 3.3.2.1.20)

sheets exposed to boraflex

treated water degradation

(3.3.1-36)

Stainless steel Cracking due to BWR Reactor Water Chemistry Consistent with

piping, piping stress corrosion Water Cleanup Control-BWR GALL Report, which

components, and cracking, System (B.1.29.2) and One recommends no

piping elements intergranular stress Time Inspection further evaluation

exposed to treated corrosion cracking (B.1.21) (See SER

water > 60'C Section 3.3.2.1.1)

(> 1400 F)

(3.3.1-37)

Stainless steel Cracking due to BWR Stress Water Chemistry Consistent with

piping, piping stress corrosion Corrosion Cracking Control-BWR GALL Report, which

components, and cracking and Water (B.1.29.2) and One recommends no

piping elements Chemistry Time Inspection further evaluation

exposed to treated (B.1.21) (See SER

water > 60oC Section 3.3.2.1.2)

(> 140°F)

(3.3.1-38)

3-253
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Crackihg due to Water Chemistry Not Applicable Not applicable (See

BWR spent fuel stress corrosion SER

storage racks cracking Section 3.3.2.1.20)

exposed to treated

water > 60 0C

(> 1400F)

(3.3.1-39)

Steel tanks in diesel Loss of material Aboveground Steel Not Applicable Not applicable (See

fuel oil system due to general, Tanks SER

exposed to air pitting, and crevice Section 3.3.2.1.20)

outdoor (external) corrosion

(3.3.1-40)

High-strength steel Cracking due to Bolting Integrity Not Applicable Not applicable (See

closure bolting cyclic loading, SER

exposed to air with stress corrosion Section 3.3.2.1.20)

steam or water cracking

leakage

(3.3.1-41)

Steel closure Loss of material Bolting Integrity Not Used Not used (See SER

bolting exposed to due to general Section 3.3.2.1.21)

air with steam or corrosion

water leakage

(3.3.1-42)

Steel bolting and Loss of material Bolting Integrity Bolting Integrity Consistent with

closure bolting due to general, (B.1.30) GALL Report, which

exposed to air - pitting, and crevice recommends no

indoor uncontrolled corrosion further evaluation

(external) or air - (See SER

outdoor (External) Section 3.3.2.1)

(3.3.1-43)

Steel compressed Loss of material Bolting Integrity Bolting Integrity Consistent with

air system closure due to general, (B.1.30) GALL Report, which

bolting exposed to pitting, and crevice recommends no

condensation corrosion further evaluation

(3.3.1-44) (See SER

Section 3.3.2.1)

Steel closure Loss of preload due Bolting Integrity Bolting Integrity Consistent with

bolting exposed to to thermal effects, (B.1.30) GALL Report, which

air - indoor gasket creep, and recommends no

uncontrolled self-loosening further evaluation

(external) (See SER

(3.3.1-45) Section 3.3.2.1.3)

3-254
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Cracking due to Closed-Cycle Water Chemistry Consistent with

stainless clad steel stress corrosion Cooling Water Control-Closed GALL Report, which

piping, piping cracking System Cooling Water recommends no

components, piping (B.1.29.3) or Water further evaluation

elements, and heat Chemistry (See SER

exchanger Control-Auxiliary Section 3.3.2.1.4)

components Systems (B.1.29.1)

exposed to closed

cycle cooling

water > 60'C

(> 140TF)

(3.3.1-46) !

Steel piping, piping Loss of material Closed-Cycle Water Chemistry Consistent with

components, piping due to general, Cooling Water Control-Closed GALL Report, which

elements, tanks, pitting, and crevice System Cooling Water recommends no

and heat exchanger corrosion (B.1.29.3), Water further evaluation

components Chemistry (See SER

exposed to closed Control-Auxiliary Section 3.3.2.1.5)

cycle cooling water Systems (B.1.29.1),

(3.3.1-47) Fire Protection

(B.1.13.1), or

Periodic

Surveillance and

Preventive

Maintenance

(B.1.22)

Steel piping, piping Loss of material Closed-Cycle Water Chemistry Consistent with

components, piping due to general, Cooling Water Control-Closed GALL Report, which

elements, tanks, pitting, crevice, and System Cooling Water recommends no

and heat exchanger galvanic corrosion (B.1.29.3), Water further (See SER

components Chemistry Section 3.3.2.1.6)

exposed to closed Control-Auxiliary

cycle cooling water Systems (B.1.29.1)

(3.3.1-48) or Fire Protection

(B.1.13.1)

Stainless steel; Loss of material Closed-Cycle Water Chemistry Consistent with

steel with stainless due to Cooling Water Control-Closed GALL Report, which

steel cladding heat microbiologically System Cooling Water recommends no

exchanger influenced corrosion (B.1.29.3) or Water further evaluation

components Chemistry (See SER

exposed to closed Control-Auxiliary Section 3.3.2.1.7)

cycle cooling water Systems (B.1.29.1)

(3.3.1-49)

Stainless steel Loss of material Closed-Cycle Water Chemistry Consistent with

piping, piping due to pitting and Cooling Water Control-Closed GALL Report, which

components, and crevice corrosion System Cooling Water recommends no

piping elements (B. 1.29.3) or Water further evaluation

exposed to closed Chemistry (See SER

cycle cooling water Control-Auxiliary Section 3.3.2.1.8)

(3.3.1-50) Systems (B.1.29.1)

3-255
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Copper alloy piping, Loss of material Closed-Cycle Water Chemistry Consistent'with

piping components, due to pitting, Cooling Water Control-Closed GALL Report, which

piping elements, crevice, and System Cooling Water recommends no

and heat exchanger galvanic corrosion (B.1.29.3), Water further evaluation

components Chemistry (See SER

exposed to closed Control-Auxiliary Section 3.3.2.1.9)

cycle cooling water Systems (B.1.29.1)

(3.3.1-51) or Fire Protection

(B.1.13.1)

Steel, stainless Reduction of heat Closed-Cycle Water Chemistry Consistent with

steel, and copper transfer due to Cooling Water Control-Closed GALL Report, which

alloy heat fouling i System Cooling Water recommends no

exchanger tubes, (B.11.29.3), Water further evaluation

exposed to closed Chemistry (See SER

cycle cooling water Control-Auxiliary Section 3.3.2.1.10)

(3.3.1-52) Systems (B.1.29.1)

or Fire Protection

(B.1.13.1)

Steel compressed Loss of material Compressed Air Not Applicable Not applicable (See

air system piping, due to general and Monitoring SER

piping components, pitting corrosion Section 3.3.2.1.20)

and piping elements

exposed to

condensation

(internal)

(3.3.1-53)

Stainless steel Loss of material Compressed Air Not Applicable Not applicable (See

compressed air due to pitting and Monitoring SER

system piping, crevice corrosion Section 3.3.2.1.20)

piping components,

and piping elements

exposed to internal

condensation

(3.3.1-54)

Steel ducting Loss of material External Surfaces Extemal Surfaces Consistent with

closure bolting due to general Monitoring Monitoring (B.1.11) GALL Report, which

exposed to air - corrosion recommends no

indoor uncontrolled further evaluation

(external) (See SER

(3.3.1-55) Section 3.3.2.1)

Steel HVAC ducting Loss of material External Surfaces External Surfaces Consistent with

and components due to general Monitoring Monitoring (B.1.11) GALL Report, which

external surfaces corrosion recommends no

exposed to air - further evaluation

indoor uncontrolled (See SER

(external) Section 3.3.2.1)

(3.3.1-56)

3-256
Component Group Aging Effectl AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel piping and Loss of material External Surfaces External Surfaces Consistent with

components due to general Monitoring Monitoring (B. 1.11) GALL Report, which

external surfaces corrosion recommends no

exposed to air - further evaluation

indoor uncontrolled (See SER

(External) Section 3.3.2.1)

(3.3.1-57)

Steel external Loss of material External Surfaces External Surfaces Consistent with

surfaces exposed to due to general Monitoring Monitoring (B.1.11) GALL Report, which

air - indoor corrosion or Fire Protection recommends no

uncontrolled (B. 1.13. 1) further evaluation

(external), air - (See!SER

outdoor (external), Section 3.3.2.1.11)

and condensation

(external)

(3.3.1-58)

Steel heat Loss of material External Surfaces External Surfaces Consistent with

exchanger due to general, Monitoring Monitoring (B.1.11) GALL Report, which

components pitting, and crevice recommends no

exposed to air - corrosion further evaluation

indoor uncontrolled (See SER

(external) or air Section 3.3.2.1)

-outdoor (external)

(3.3.1-59)

Steel piping, piping Loss of material External Surfaces External Surfaces Consistent with

components, and due to general, Monitoring Monitoring (B.1.11) GALL Report, which

piping elements pitting, and crevice recommends no

exposed to air - corrosion further evaluation

outdoor (external) (See SER

(3.3.1-60) Section 3.3.2.1)

Elastomer fire Increased Fire Protection Not used Not used (See SER

barrier penetration hardness, Section 3.3.2.1.21)

seals exposed to shrinkage and loss

air - outdoor or of strength due to

air - indoor weathering

uncontrolled

(3.3.1-61)

Aluminum piping, Loss of material Fire Protection One-Time Consistent with

piping components, due to pitting and Inspection (B.1.21) GALL Report, which

and piping elements crevice corrosion recommends no

exposed to raw further evaluation

water (See SER

(3.3.1-62) Section 3.3.2.1.12)

Steel fire rated Loss of material Fire Protection Not used Not used (See SER

doors exposed to due to Wear Section 3.3.2.1.21)

air - outdoor or

air - indoor

uncontrolled

(3.3.1-63)

3-257
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel piping, piping Loss of material Fire Protection and Fire Protection Consistent with

components, and due to general, Fuel Oil Chemistry (B.1.13.1) and GALL Report, which

piping elements pitting, and crevice Diesel Fuel recommends no

exposed to fuel oil corrosion Monitoring (B.1.9) further evaluation

(3.3.1-64) (See SER

Section 3.3.2.1)

Reinforced concrete Concrete cracking Fire Protection and Not used Not used (See SER

structural fire and spalling due to Structures Section 3.3.2.1.21)

barriers - walls, aggressive Monitoring Program

ceilings and floors chemical attack,

exposed to air - and reaction with

.indoor uncontrolled aggregates

(3.3.1-65)

Reinforced concrete Concrete cracking Fire Protection and Not used Not used (See SER

structural fire and spalling due to Structures Section 3.3.2.1.21)

barriers - walls, freeze thaw, Monitoring Program

ceilings and floors aggressive

exposed to air - chemical attack,

outdoor and reaction with

(3.3.1-66) aggregates

Reinforced concrete Loss of material Fire Protection and Not used Not used (See SER

structural fire due to corrosion of Structures Section 3.3.2.1.21)

barriers - walls, embedded steel Monitoring Program

ceilings and floors

exposed to air -

outdoor or air -

indoor uncontrolled

(3.3.1-67)

Steel piping, piping, Loss of material Fire Water System Fire Water System Consistent with

components, and due to general, (B.1.13.1) or Fire GALL Report, which

piping elements pitting, crevice, and Protection recommends no

exposed to raw microbiologically (B. 1.13.2) further evaluation

water influenced (See SER

(3.3.1-68) corrosion, and Section 3.3.2.1.13)

fouling

Stainless steel Loss of material Fire Water System Fire Water System Consistent with

piping, piping due to pitting and (B.i.13.2) GALL Report, which

components, and crevice corrosion, recommends no

piping elements and fouling further evaluation

exposed to raw (See SER

water Section 3.3.2.1)

(3.3.1-69)

Copper alloy piping, Loss of material Fire Water System Fire Water System Consistent with

piping components, due to pitting, (B.1.13.2) GALL Report, which

and piping elements crevice, and recommends no

exposed to raw microbiologically further evaluation

water influenced (See SER

(3.3.1-70) corrosion, and Section 3.3.2.1)

fouling

3-258
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel piping, piping Loss of material Inspection of Periodic Consistent with

components, and due to general, Internal Surfaces in Surveillance and GALL Report, which

piping elements pitting, and crevice Miscellaneous Preventive recommends no

exposed to moist air corrosion Piping and Ducting Maintenance further evaluation

or condensation Components (B.1.22) (See SER

(Internal) Section 3.3.2.1.14)

(3.3.1-71)

Steel HVAC ducting Loss of material Inspection of Not applicable Not applicable See

and components due to general, Internal Surfaces in SER

internal surfaces,- pitting,.crevice, and Miscellaneous Section 3.3.2.1.20)

exposed to. (for drip pans and -Piping and Ducting

condensation drain lines),; -p - Components

(Internal) microbiologically

(3.3.1-72) influenced corrosion

Steel crane Loss of material Inspection of Not Used Not used (See SER

structural girders in due to general Overhead Heavy Section 3.3.2.1.21)

load handling corrosion. Load and Light

system exposed to Load (Related to

air - indoor Refueling) Handling

uncontrolled Systems

(external)

(3.3.1-73)

Steel cranes - rails Loss of material Inspection of Not Used Not used (See SER

exposed to air - due to Wear Overhead Heavy Section 3.3.2.1.21)

indoor uncontrolled Load and Light

(external) Load (Related to

(3.3.1-74) Refueling) Handling

Systems

Elastomer seals Hardening and loss Open-Cycle Cooling Not Applicable Not applicable (See

and components of strength due to Water System SER

exposed to raw elastomer Section 3.3.2.1.20)

water degradation; loss of

(3.3.1-75) material due to

erosion

Steel piping, piping Loss of material Open-Cycle Cooling Service Water Consistent with

components, and due to general, Water System Integrity (B.1.26) or GALL Report, which

piping elements pitting, crevice, and Periodic recommends no

(without lining/ microbiologically Surveillance and further evaluation

coating or with influenced Preventive (See SER

degraded corrosion, fouling, Maintenance Section 3.3.2.1.15)

lining/coating) and lining/coating (B.1.22)

exposed to raw degradation

water

(3.3.1-76)_

3-259
Component Group Aging Effect/ AMP in GALL AMP In LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel heat Loss of material Open-Cycle Cooling Service Water Consistent with

exchanger due to general, Water System Integrity (B.1.26) or GALL Report, which

components pitting, crevice, Periodic recommends no

exposed to raw galvanic, and Surveillance and further evaluation

water microbiologically Preventive (See SER

(3.3.1-77) influenced Maintenance Section 3.3.2.1.16)

corrosion, and (B.1.22)

fouling

Stainless steel, Loss of material Open-Cycle Cooling Service Water Consistent with

nickel alloy, and due to pitting and Water System Integrity (B.1.26) GALL Report, which

copper alloy piping, crevice corrosion recommends no

piping components, further evaluation

and piping elements (See SER

exposed to raw Section 3.3.2.1)

water

(3.3.1-78)

Stainless steel Loss of material Open-Cycle Cooling Service Water Consistent with

piping, piping due to pitting and Water System Integrity (B.1.26), GALL Report,- which

components, and crevice corrosion, One-Time recommends no

piping elements and fouling Inspection (B.1.21), further evaluation

exposed to raw or Periodic (See SER

water Surveillance and Section 3.3.2.1.17)

(3.3.1-79) Preventive

Maintenance

(B.1.22)

Stainless steel and Loss of material Open-Cycle Cooling Not Used Not used (See SER

copper alloy piping, due to pitting, Water System Section 3.3.2.1.21)

piping components, crevice, and

and piping elements microbiologically

exposed to raw influenced corrosion

water

(3.3.1-80)

Copper alloy piping, Loss of material Open-Cycle Cooling Service Water Consistent with

piping components, due to pitting, Water System Integrity (B.1.26), GALL Report, which

and piping crevice, and One-Time recommends no

elements, exposed microbiologically Inspection (B.1.21), further evaluation

to raw water influenced or Periodic (See SER

(3.3.1-81) corrosion, and Surveillance and Section 3.3.2.1.18)

fouling Preventive

Maintenance

(B.1.22)

Copper alloy heat Loss of material Open-Cycle Cooling Service Water Consistent with

exchanger due to pitting, Water System Integrity (B.1.26) GALL Report, which

components crevice, galvanic, recommends no

exposed to raw and further evaluation

water microbiologically (See SER

(3.3.1-82) influenced Section 3.3.2.1)

corrosion, and

fouling

3-260
Component Group Aging Effect/ AMP In GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and Reduction of heat Open-Cycle Cooling Service Water Consistent With

copper alloy heat transfer due to Water System Integrity (B.1.26), GALL Report, which

exchanger tubes fouling Fire Protection recommends no

exposed to raw (B.1.13.1), or further evaluation

water Periodic (See SER

(3.3.1-83) Surveillance and Section 3.3.2.1.19)

Preventive

Maintenance

(B.1.22)

Copper alloy Loss of material Selective Leaching Selective Leaching Consistent with

> 15% Zn piping, due to selective of Materials (B.1.25) GALL Report, which

piping components, leaching recommends no

piping elements, further evaluation

and heat exchanger (See SER

components Section 3.3.2.1)

exposed to raw

water, treated

water, or closed

cycle cooling water

(3.3.1-84)

Gray cast iron Loss of material Selective Leaching Selective Leaching Consistent with

piping, piping due to selective of Materials (B.1.25) GALL Report, which

components, and leaching recommends no

piping elements further evaluation

exposed to soil, raw (See SER

water, treated Section 3.3.2.1)

water, or

closed-cycle cooling

water

(3.3.1-85)

Structural steel Loss of material Structures Not Used Not used (See SER

(new fuel storage due to general, Monitoring Program Section 3.3.2.1.21)

rack assembly) pitting, and crevice

exposed to air - corrosion

indoor uncontrolled

(external)

(3.3.1-86)

Boraflex spent fuel Reduction of Boraflex Monitoring Not Applicable Not applicable to

storage racks neutron-absorbing BWRs

neutron-absorbing capacity due to

sheets exposed to boraflex

treated borated degradation

water

(3.3.1-87)

3-261
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Aluminum and Loss of material Boric Acid Not Applicable Not applicable to

copper alloy due to Boric acid Corrosion BWRs

> 15% Zn piping, corrosion

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.3.1-88)

Steel bolting and Loss of material Boric Acid Not Applicable Not applicable to

external surfaces due to Boric acid Corrosion BWRs

exposed to air with corrosion

borated water

leakage

(3.3.1-89)

Stainless steel and Cracking due to Water Chemistry Not Applicable Not applicable to

steel with stainless stress corrosion BWRs

steel cladding cracking

piping, piping

components, piping

elements, tanks,

and fuel storage

racks exposed to

treated borated

water > 60'C

(> 140 0 F)

(3.3.1-90)

Stainless steel and Loss of material Water Chemistry Not Applicable Not applicable to

steel with stainless due to pitting and BWRs

steel cladding crevice corrosion

piping, piping

components, and

piping elements

exposed to treated

borated water

(3.3.1-91)

Galvanized steel None None Not Applicable Not applicable (See

piping, piping SER

components, and Section 3.3.2.1.20)

piping elements

exposed to air -

indoor uncontrolled

(3.3.1-92)

3-262
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

ItemNo.) ________ ________________ _______

Glass piping None None None Consistent with

elements exposed GALL Report

to air, air - indoor

uncontrolled

(external), fuel oil,

lubricating oil, raw

water, treated

water, and treated

borated water

(3.3.1-93) ________ ________ ________

Stainless steel and None None None' Consistent with

nickel alloy piping, GALL Report

piping components,

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.3.1-94) ________ ________ ________

Steel and aluminum None None Not Applicable Not applicable (See

piping, piping SER

components, and Section 3.3.2.1.20)

piping elements

exposed to air -

indoor controlled

(external)

(3.3.1-95) ____________ ____

Steel and stainless None None None Consistent with

steel piping, piping GALL Report

components, and

piping elements in

concrete

(3.3.1-96) ________ ________ ________

Steel, stainless None None None Consistent with

steel, aluminum, GALL Report

and copper alloy

piping, piping

components, and

piping elements

exposed to gas

(3.3.1-97) ________ ________

Steel, stainless None None None Consistent with

steel, and copper GALL Report

alloy piping, piping

components, and

piping elements

exposed to dried air

(3.3.1-98) __________________

3-263
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel and None None Not Applicable Not applicable to

copper alloy BWRs

< 15% Zn piping,

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.3.1-99)

The staff's review of the auxiliary systems component groups followed one of several

approaches. One approach, documented in SER Section 3.3.2.1, discusses the staff's review of

the AMR results for components that the applicant indicated are consistent with the GALL

Report and do not require further evaluation. Another approach, documented in SER

Section 3.3.2.2, discusses the staffs review of the AMR results for components that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.3.2.3, discusses the staff's

review of the AMR results for components that the applicant indicated are not consistent with,

or not addressed in, the GALL Report. The staffs review of AMPs that are 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 That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the auxiliary systems components:

" Buried Piping and Tanks Inspection Program

* Diesel Fuel Monitoring Program

" External Surfaces Monitoring Program

" Fire Protection Program

* Fire Water System Program

* Flow-Accelerated Corrosion Program

* Heat Exchanger Monitoring Program

* Oil Analysis Program

* One-Time Inspection Program

* Periodic Surveillance and Preventive Maintenance Program

* Selective Leaching Program

" Service Water Integrity Program

" Water Chemistry Control - Auxiliary Systems Program

" Water Chemistry Control - BWR Program

" Water Chemistry Control - Closed Cooling Water Program

* Bolting Integrity Program

3-264
In LRA Tables 3.3.2-1 through 3.3.2-13, 3.3.2-14-5, 3.3.2-14-6, 3.3.2-14-9, 3.3.2-14-11,

3.3.2-14-12, 3.3.2-14-13, 3.3.2-14-15, 3.3.2-14-18, 3.3.2-14-23 through 3.3.2-14-41,

3.3.2-14-43, and 3.3.2-1 4-44, the applicant provided a summary of AMRs for the auxiliary

systems components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report does not

recommend further evaluation, the staff performed an audit and review to determine whether

the plant-specific components contained in these GALL Report component groups were

bounded by the GALL Report evaluation.

The applicant provided -a note for~each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report.* The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant is consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the AMP identified by the GALL Report. This note indicates that the

applicant was unable to find a listing of some system components in the GALL Report;

however, the applicant identified a different component in the GALL Report that has the same

material, environment, aging effect, and AMP as the component that was under review. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the AMR line item of the different component was applicable to the

component under review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these

line items to verify consistency with the GALL Report. The staff verified whether the AMR line

item of the different component was applicable to the component under review. The staff

verified whether the identified exceptions to the GALL AMPs had been reviewed and accepted

by the staff. The staff also determined whether the AMP identified by the applicant was

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the

site-specific conditions.

3-265
Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified in the GALL

Report and whether the AMR was valid for the site-specific conditions.

3.3.2.1.1 Cracking due to Stress Corrosion Cracking and Intergranular Stress Corrosion

Cracking

LRA Table 3.3.1, Item 3.3.1-37, addresses cracking due to stress corrosion cracking (SCC) and

intergranular stress corrosion cracking (IGSCC) for stainless steel piping, piping components,

and piping elements exposed to treated water >600C (>1400 F) in the auxiliary systems. The

LRA credits the Water Chemistry Control-BWR Program together with the One-Time Inspection

Program. The GALL Report recommends AMP XI.M25, "BWR Reactor Water Cleanup

System," to manage this aging effect. The LRA states that the only components to which this

GALL Report line item applies are included in license renewal scope only under criterion

10 CFR 54.4(a)(2) and listed in table 3.3.2-14-6 for nonsafety-related reactor water cleanup

system components affecting safety-related systems. The Table 2 AMR line items in the LRA

that reference this Table 1 line item cite Generic Note E, indicating that the-AMR line items are

consistent with the GALL Report material, environment, and aging effect, but a different aging

management program is credited.

In LRA Table 3.3.1, Item 3.3.1-37, the applicant stated that the BWR Reactor Water Cleanup

System Program is not credited for license renewal. The GALL Report states that no IGSCC

inspection is recommended for plants that have piping made of material that is resistant to

IGSCC and have satisfactorily completed all actions requested in NRC GL 89-10. The applicant

states that since JAFNPP satisfies these criteria, the Water Chemistry Control-BWR Program is

used in lieu of the reactor water cleanup system program to manage cracking. The One-Time

Inspection Program will be used to verify the effectiveness of the water chemistry program.

The staff reviewed GALL AMP XI.M25 and determined that it includes water chemistry control

activities and in-service inspections. Also, the staff reviewed GL 89-10 and the applicant's

response and confirmed that no IGSCC inspection is recommended for plants that have piping

made of material that is resistant to IGSCC and have satisfactorily completed all actions

requested. The staff also reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.10

and 3.0.3.1.6, respectively. The staff determined that it includes activities that will maintain high

water purity and the applicant's Water Chemistry Control-BWR Program is consistent with

GALL AMP XI.M25, which is effective for managing cracking due to SCC and IGSCC for

stainless steel components exposed to treated water. The staff determined that a One-Time

Inspection will be effective in detecting any cracking in these Reactor Water Cleanup nonsafety

components. Since the applicant is crediting the Water Chemistry Control-BWR Program and

the One-Time Inspection Program, the staff finds that the activities being credited are adequate

to manage these aging effects and are acceptable.

3-266
On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the aging effect/mechanism (AEM) appropriately as

recommended by the GALL Report.

3.3.2.1.2 Cracking due to Stress Corrosion Cracking [1]

LRA Table 3.3.1, Item 3.3.1-38, addresses cracking due to stress corrosion cracking (SCC) for

stainless steel piping, piping components, and piping elements exposed to treated water >60 °C

(>140 OF) in the auxiliary systems. The LRA credits the Water Chemistry Control-BWR Program

together with the One-Time Inspection Program. The GALL Report recommends AMPs XI.M7,

"BWR Stress Corrosion Cracking," and XI.M2, "Water Chemistry," to manage this aging effect.

The LRA states that the only components to which this GALL Report line item applies are

included within the scope of license renewal only under criterion 10 CFR 54.4(a)(2), and are

listed in table 3.3.2-14-15 (containment purge, containment atmospheric dilution, and

post-accident sampling), 3.3.2-14-18 (decay heat removal), 3.3.2-14-24 (Vacuum Priming and

Air Removal), 3.3.2-14-27 (Secondary Plant Drains), and 3.3.2-14-43 (Sample system) for

nonsafety-related components affecting safety-related systems. The Table 2 AMR line items in

the LRA that reference this Table 1 line item cite Generic Note E, indicating that the AMR line

items are consistent with the GALL Report material, environment, and aging effect, but a

different aging management program is credited.

In Table 3.3.1, Item 3.3.1-38, the applicant stated that none of the auxiliary system components

addressed by this AMR line item are within the scope of the BWR Stress Corrosion Cracking

Program (all relevant components are included in the reactor vessel, internals and reactor

coolant systems). Therefore, the Water Chemistry Control-BWR Program is used to manage

cracking of stainless steel components. The One-Time Inspection Program will be used to

verify the effectiveness of the water chemistry program.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time

Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.10 and

3.0.3.1.6, respectively. The staff confirmed that they are nonsafety-related components, and

are not within the scope of the applicant's BWR Stress Corrosion Cracking Program. The staff

determined that the Water Chemistry Control-BWR Program includes activities that are

consistent with the recommendations in GALL AMP XI.M7 to maintain high water purity, which

is effective for managing cracking due to SCC for stainless steel components exposed to

treated water. The staff noted that these are nonsafety-related components in auxiliary systems

and a one-time inspection will be effective in detecting any cracking. Since the applicant is

crediting the Water Chemistry Control-BWR Program and the One-Time Inspection Program,

the staff determined that the activities being credited are adequate to manage these aging

effects.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.3 Loss of Preload due to Thermal Effects, Gasket Creep, and Self Loosening

3-267
LRA Table 3.3.1, Item 3.3.1-45, addresses loss of preload due to thermal effects, gasket creep,

and self loosening for steel closure bolting exposed to uncontrolled, external, indoor air in the

auxiliary systems. The LRA states that this aging effect is not applicable for auxiliary systems

and no aging management program is credited. The GALL Report recommends GALL

AMP XI.M18, "Bolting Integrity," to manage this aging effect.

During the audit and review, the staff asked the applicant to clarify why this aging effect is not

applicable at JAFNPP. In its response, the applicant stated that this position is consistent with

the EPRI Mechanical Tools report (EPRI 1010639); however, the bolting integrity program is

currently used at JAFNPP to monitor these components. The applicant committed to amend the

LRA to delete "Not Applicable" from this AMR line item. In its letter dated February 1, 2007, the

applicant amended the LRA to delete "Not Applicable" from the discussion column of AMR line

Item 3.3.1-45. The staff reviewed the applicant's bolting integrity program and its evaluations

are documented in SER Section 3.0.3.2.20. The staff determined that it is consistent with the

recommendations in GALL AMP XI.M18 and includes activities that will manage loss of preload

for these components. On this basis, the staff finds the AMR results for this line item

acceptable.

3.3.2.1.4 Cracking due to Stress Corrosion Cracking [2]

LRA Table 3.3.1, Item 3.3.1-46, addresses cracking due to stress corrosion cracking (SCC) for

stainless steel and stainless clad steel piping, piping components, piping elements, and heat

exchanger components exposed to closed cycle cooling water >60 0C (>1400 F) in the auxiliary

systems. The LRA credits the Water Chemistry Control-Closed Cooling Water Program or the

Water Chemistry Control-Auxiliary Systems Program. The GALL Report recommends GALL

AMP XI.M21, "Closed-Cycle Cooling Water," to manage this aging effect. The LRA states that

the only components to which this GALL Report line item applies are included in-scope only

under criterion 10 CFR 54.4(a)(2) and are listed in table 3.3.2-14-6 (RWCU system heat

exchanger shell) and 3.3.2-14-40 (tubing for the auxiliary boiler and accessories) for

nonsafety-related components affecting safety-related systems. The Table 2 AMR line items in

the LRA that reference this Table 1 line item and credit the Water Chemistry Control-Auxiliary

Systems Program cite Generic Note E, indicating that the AMR line items are consistent with

the GALL Report material, environment, and aging effect, but a different AMP is credited.

These AMR line items include a plant-specific note stating that the treated water environment is

auxiliary boiler water which does not directly compare with any GALL Report environment, but

closely approximates the GALL Report-defined treated water environment.

The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and

its evaluations are documented in SER Section 3.0.3.2.19. The staff verified that this aging

management program is consistent with the recommendations in the GALL AMP XI.M21 to

maintain high water purity, which is effective for managing cracking due to SCC for stainless

steel and stainless clad steel components exposed to closed cycle cooling water. The staff

confirmed that the One-Time Inspection Program will be used to verify the effectiveness of this

program to manage cracking. On this basis, the staff finds that AMR results addressed by this

line item that credit the Water Chemistry Control-Closed Cooling Water Program are consistent

with the GALL Report, and are acceptable.

The staff also reviewed the Water Chemistry Control-Auxiliary Systems Program and One-Time

Inspection Program and its evaluations are documented in SER Sections 3.0.3.3.5 and

3-268
3.0.3.1.6, respectively. The staff determined that the Water Chemistry Control-Auxiliary

Systems Program includes activities that are consistent with the recommendations in GALL

AMP XI.M21 to maintain high water purity, which is effective for managing cracking due to SCC

for stainless steel and stainless .clad steel components exposed to closed cycle cooling water.

The staff noted that the components for which this AMP is credited are nonsafety components

in auxiliary systems, and that a one-time inspection will be effective in detecting any cracking.

Since the applicant is crediting the Water Chemistry Control-Auxiliary Systems Program with

the One-Time Inspection Program for verification of effectiveness, the activities being credited

are consistent with GALL AMP XI.M21 recommendations to manage these aging effects. On

this basis, the staff finds that AMR results addressed by this line item that credit the Water

Chemistry Control-Auxiliary Systems Program are acceptable.

3.3.2.1.5 Loss of Material-due to General,. Pitting, and Crevice Corrosion

LRA Table 3.3.1, Item 3.3.1-47, addresses loss of material due to general, pitting, and crevice

corrosion for steel piping, piping components, piping elements, tanks, and heat exchangers

exposed to closed cycle cooling water. The LRA credits the Water Chemistry Control-Closed

Cooling Water Program, Water Chemistry Control-Auxiliary Systems Program, Fire Protection

Program, or the Periodic Surveillance and Preventive Maintenance Program. The GALL Report

recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System," to manage this aging

effect. Table 2 AMR line items in the LRA that reference this Table 1 line item and credit the

Water Chemistry Control-Auxiliary Systems Program, Fire Protection Program, or the Periodic

Surveillance and Preventive Maintenance Program cite Generic Note E, indicating that the AMR

line items are consistent with the GALL Report material, environment, and aging effect, but a

different aging management program is credited.

The AMR line items that credit the Water. Chemistry Control-Auxiliary Systems Program are for

components in Tables 3.3.2-7 (HVAC system), 3.3.2-14-32 (Reactor Building Ventilation),

3.3.2-14-33 (Turbine Building Ventilation), 3.3.2-14-34 (Drywell Ventilation and Cooling),

3.3.2-14-14-35 (Administration Building Ventilation and Cooling), 3.3.2-14-40 (Auxiliary Boiler

and Accessories), and 3.3.2-14-42 (Main Generator Stator Cooling). Plant-specific notes are

also cited: for HVAC, indicating that this component is part of the chilled water subsystem for

the control room HVAC system and that although this environment does notdirectly compare

with any GALL Report defined environment, it approximates the GALL Report defined closed

cooling water environment; for the reactor building, turbine building, drywell, and administration

building ventilation and cooling systems, indicating that this treated water system environment

is plant heating system water and that although this environment does not directly compare with

any GALL Report defined environment, it approximates the GALL Report defined closed cooling

water environment; for the auxiliary boiler, indicating that this treated water system environment

is auxiliary boiler system water and that although this environment does not directly compare

with any GALL Report defined environment, it approximates the GALL Report defined closed

cooling water environment; and for the main generator stator cooling, indicating that this treated

water system environment is main generator stator cooling water and that although this

environment does not directly compare with any GALL Report defined environment, it

approximates the GALL Report defined closed cooling water environment.

In addition to the water chemistry control programs, the LRA credits the Fire Protection

Program for managing loss of material due to general, pitting, and crevice corrosion for AMR

line items in Table 3.3.2-5 for steel piping and steel valve body components in the Fire

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Protection-Water system, and the Periodic Surveillance and Preventive Maintenance Program

for managing loss of material due to general, pitting, and crevice corrosion for AMR line items in

Table 3.3.2-14-23 for steel piping in the TBCLC system. Plant-specific Notes for the Fire

Protection Program indicate that the treated water environment is engine jacket cooling water,

and for the Periodic Surveillance and Preventive Maintenance Program indicate that the

portions of the TBCLC system piping that are subject to erosion are included in augmented

inspections for flow accelerated corrosion as part of the Periodic Surveillance and Preventive

Maintenance Program.

The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and

its evaluation is documented in SER Section 3.0.3.2.19. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting, and crevice corrosion for steel components exposed to closed

cycle cooling water. The staff confirmed that the One-Time Inspection Program will be used to

verify the effectiveness of the applicant's Water Chemistry Control-Closed Cooling Water

Program to manage loss of material. On this basis, the staff finds that AMR results addressed

by this line item that credit the Water Chemistry Control-Closed Cooling Water Program are

consistent with the GALL Report and are acceptable.

The staff also reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program

and its evaluation is documented in SER Section 3.0.3.3.5. The staff determined that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting, and crevice corrosion for steel components exposed to closed

cycle cooling water. The staff confirmed that the one-time inspection program will be used to

verify the effectiveness of the applicant's Water Chemistry Control-Auxiliary Systems Program

to manage loss of material. On this basis, the staff finds that AMR results addressed by this line

item that credit the Water Chemistry Control-Auxiliary Systems Program are acceptable.

The staff reviewed the applicant's Fire Protection Program and determined that this program

includes periodic testing and inspection of the fire pump and engine to ensure that the engine

subsystems can perform their intended function. The staff finds that these inspections will be

effective to detect loss of material. On this basis, the staff finds that AMRs addressed by this

line item that credit the Fire Protection Program are acceptable.

Finally, the staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance

Program and verified that this aging management program includes augmented inspections

using NDE techniques that will be effective to detect loss of material. On this basis, the staff

finds that AMR results addressed by this line item that credit the Periodic Surveillance and

Preventive Maintenance Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.6 Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion

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LRA Table 3.3.1, Item 3.3.1-48, addresses loss of material due to general, pitting, crevice, and

galvanic corrosion for steel piping, piping components, piping elements, tanks, and heat

exchanger components exposed to closed cycle cooling water in the auxiliary systems. The

LRA credits the Water Chemistry Control-Closed Cooling Water Program, Water Chemistry

Control-Auxiliary Systems Program, or the Fire Protection Program. The GALL Report

recommends AMP XI.M21, "Closed-Cycle Cooling Water System," to manage this aging effect.

The Table 2 AMR line items in the LRA that reference this Table 1 line item and credit the

Water Chemistry Control-Auxiliary Systems Program or the Fire Protection Program cite

Generic Note E, indicating that the AMR line items are consistent with the GALL Report

material, environment, and aging effect, but a different aging management program is credited.

The LRA states that the AMR that credits the Water Chemistry Control-Auxiliary Systems

Program, listed in Table 3.3.2-7 (HVAC system), is consistent with the GALL AMP XI.M21

which recommends no further evaluation. It also cites a plant-specific note indicating that this

component is part of the chilled water subsystem of the control room HVAC system and that

although this environment does not directly compare with any GALL Report defined

environment, it approximates the GALL Report defined closed cycle cooling water environment.

The LRA credits the Fire Protection Program for managing loss of material due to general,

pitting, crevice, and galvanic corrosion for the AMR line items in Table 3.3.2-5 for a gray cast

iron heat exchanger shell in the Fire Protection-Water system. A plant-specific note indicates

that the treated water environment is engine jacket cooling water.

The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and

its evaluation is documented in SER Section 3.0.3.2.19. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting, crevice, and galvanic corrosion for steel components exposed

to closed cycle cooling water. The staff confirmed that the one-time inspection program will be

used to verify the effectiveness of the applicant's Water Chemistry Control-Closed Cooling

Water Program to manage loss of material. On this basis, the staff finds that AMR results

addressed by this line item that credit the Water Chemistry Control-Closed Cooling Water

Program are consistent with GALL AMP XI.M21 and are acceptable.

The staff also reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program

and its evaluation is documented in SER Section 3.0.3.3.5. The staff determined that this aging

management program includes activities that are consistent with the recommendations in GALL

AMP XI.M21 to maintain high water purity, which is effective for managing loss of material due

to general, pitting, crevice, and galvanic corrosion for steel components exposed to closed

cycle cooling water. The staff confirmed that the One-Time Inspection Program will be used to

verify the effectiveness of the applicant's Water Chemistry Control-Auxiliary Systems Program

to manage loss of material. On this basis, the staff finds that AMR results addressed by this line

item that credit the Water Chemistry Control-Auxiliary Systems Program are acceptable.

The staff also reviewed the applicant's Fire Protection Program and its evaluation is

documented in SER Section 3.0.3.2.11. The staff determined that this program includes

periodic testing and inspection of the fire pump and engine to ensure that the engine

subsystems can perform their intended function. The staff finds that these inspections will be

effective to detect loss of material. On this basis, the staff finds that AMR results addressed by

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this line item that credit the Fire Protection Program are acceptable.

,On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.7 Loss of Material due to Microbiologically-Influenced Corrosion

LRA Table 3.3.1, Item 3.3.1-49, addresses loss of material due to MIC for stainless steel and

steel with stainless steel cladding heat exchanger components exposed to closed cycle cooling

water in the auxiliary systems. The LRA credits the Water Chemistry Control-Closed Cooling

Water Program or the Water Chemistry Control-Auxiliary Systems Program. The GALL Report

recommends AMP XI.M21, "Closed-Cycle Cooling Water System," to manage this- aging effect.

The Table 2 AMR line items crediting the Water Chemistry Control-Auxiliary Systems Program

in the LRA that references this Table 1 line item cites Generic Note E, indicating that the AMR

line items are consistent with the GALL Report material, environment, and aging effect, but a

different aging management program is credited.

The LRA states that the AMR that credits the Water Chemistry Control-Auxiliary Systems, listed

in Table 3.3.2-14-18 (Decay Heat Removal system), is consistent with the GALL Report which

recommends no further evaluation. It also cites a plant-specific note that indicates that the

treated water environment is decay heat removal system secondary cooling loop water and that

although this environment does not directly compare with any GALL Report defined

environment, it approximates the GALL Report defined closed cycle cooling water environment.

The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and the

Water Chemistry Control - Closed Cooling Water Program and its evaluations are documented

in SER Sections 3.0.3.2.19, and 3.0.3.3.5, respectively. The staff verified that these aging

management programs include activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to MIC for stainless steel and steel with stainless steel cladding components

exposed to closed cycle cooling water. The staff reviewed the applicant's One-Time Inspection

Program and its evaluation is documented in SER Section 3.0.3.1.6. The staff confirmed that

the One-Time Inspection Program will be used to verify the effectiveness of the applicant's

Water Chemistry Control-Auxiliary Systems Program and the Water Chemistry Control -

Closed Cooling Water Program to manage loss of material.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.8 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.3.1, Item 3.3.1-50, addresses loss of material due to pitting and crevice corrosion

for stainless steel piping, piping components, and piping elements exposed to closed cycle

cooling water in the auxiliary systems. The LRA credits the Water Chemistry Control-Closed

Cooling Water Program or the Water Chemistry Control-Auxiliary Systems Program. The GALL

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Report recommends AMP XI.M21, "Closed-Cycle Cooling Water System," to manage this aging

effect. The Table 2 AMR line items crediting the Water Chemistry Control-Auxiliary Systems

Program in the LRA that reference this Table 1 line item cite Generic Note E, indicating that the

AMR line items are consistent with the GALL Report material, environment, and aging effect,

but a different aging management program is credited.

The LRA states that the AMR line items that credit the Water Chemistry Control-Auxiliary

Systems, listed in Tables 3.3.2-7 (HVAC systems), 3.3.2-14-18 (Decay Heat Removal system),

and 3.3.2-14-40 (Auxiliary Boiler and Accessories) are consistent with the GALL Report which

recommends no further evaluation. Plant-specific notes are cited: for HVAC, indicating that this

component is part of the chilled water subsystem for the control room HVAC system and that

although this environment does not directly compare with any GALL Report defined

environment, it approximates the GALL Report defined closed cooling water environment; for

the decay heat removal system, indicating that the treated water environment is decay heat

removal system secondary cooling loop water and that although this environment does not

directly compare with any GALL Report defined environment, it approximates the GALL Report

defined closed cycle cooling water environment; and for the auxiliary boiler, indicating that this

treated water system environment is auxiliary boiler system water and that although this

environment does not directly compare with any GALL Report defined environment, it

approximates the GALL Report defined closed cooling water environment.

The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and the

Water Chemistry Control - Closed Cooling Water Program and its evaluations are documented

in SER Sections 3.0.3.2.19, and 3.0.3.3.5, respectively. The staff verified that these aging

management programs include activities that are consistent with the recommendations in the

GALL Report Closed-Cycle Cooling Water Chemistry Program to maintain high water purity,

which is effective for managing loss of material due to pitting and crevice corrosion for stainless

steel piping, piping components, and piping elements exposed to closed cycle cooling water.

The staff reviewed the applicant's One-Time Inspection Program and its evaluation is

documented in SER Section 3.0.3.1.6. The staff confirmed that the One-time inspection

program will be used to verify the effectiveness of the applicant's Water Chemistry

Control-Auxiliary Systems Program and the Water Chemistry Control - Closed Cooling Water

Program to manage loss of material.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.9 Loss of Material due to Pitting, Crevice, and Galvanic Corrosion

LRA Table 3.3.1, Item 3.3.1-51, addresses loss of material due to pitting, crevice, and galvanic

corrosion for copper alloy piping, piping components, piping elements, and heat exchanger

components exposed to closed cycle cooling water in the auxiliary systems. The LRA credits

the Water Chemistry Control-Closed Cooling Water Program, Water Chemistry

Control-Auxiliary Systems Program, or the Fire Protection Program. The GALL Report

recommends AMP XI.M21, " Closed-Cycle Cooling Water System," to manage this aging effect.

The Table 2 AMR line items crediting the Water Chemistry Control-Auxiliary Systems Program

or the Fire Protection Program in the LRA that reference this Table 1 line item cite Generic

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Note E, indicating that the AMR is consistent with the GALL Report material, environment, and

aging effect, but a different aging management program is credited.

The LRA states that the AMRs that credit the Water Chemistry Control-Auxiliary Systems

Program are consistent with the GALL Report which recommends no further evaluation. These

are listed in Table 3.3.2-7 (HVAC system), Table 3.3.2-13 (Security Generator),

Table 3.3.2-14-32 (Reactor Building Ventilation system), Table 3.3.2-14-33 (Turbine Building

Ventilation system), Table 3.3.2-14-34 (Drywell Ventilation and Cooling system),

Table 3.3.2-14-35 (Administration Building Ventilation and Cooling system), and

Table 3.3.2-14-36 (Screenwell/Water Treatment Ventilation and Cooling system). Plant-specific

notes are cited: for HVAC, indicating that this component is part of the chilled water subsystem

for the control room HVAC system and that although this environment does not directly

compare with any GALL Report defined environment, it approximates the GALL Report defined

closed cooling water environment; for the Security Generator, indicating that the treated water

environment is engine jacket cooling water; and for the ventilation and cooling systems,

indicating that this treated water system environment is plant heating system water and that

although this environment does not directly compare with any GALL Report defined

environment, it approximates the GALL Report defined closed cooling water environment.

The LRA credits the Fire Protection Program for managing loss of material due to pitting,

crevice, and galvanic corrosion for AMR line items in Table 3.3.2-5 in the Fire Protection-Water

system. A plant-specific note indicates that the treated water environment is engine jacket

cooling water.

The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and the

Water Chemistry Control - Closed Cooling Water Program and its evaluations are documented

in SER Sections 3.0.3.2.19, and 3.0.3.3.5, respectively. The staff verified that these aging

management programs include activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to pitting, crevice, and galvanic corrosion for copper alloy piping, piping

components, piping elements, and heat exchanger components exposed to closed cycle

cooling water in the auxiliary systems. The staff confirmed that the One-Time Inspection

Program will be used to verify the effectiveness of the applicant's Water Chemistry

Control-Auxiliary Systems Program and the Water Chemistry Control - Closed Cooling Water

Program to manage loss of material. On this basis, the staff finds that AMR results addressed

by this line item that credit the Water Chemistry Control-Auxiliary Systems Program or the

Water Chemistry Control-Closed Cooling Water Program are acceptable.

The staff also reviewed the applicant's Fire Protection Program and its evaluation is

documented in SER Section 3.0.3.2.11. The staff determined that this aging management

program includes visual inspections of diesel exhaust piping and components; and copper alloy

piping, piping components, piping elements, and heat exchanger components exposed to

engine jacket cooling water to manage loss of material. These inspections will manage loss of

material such that the intended function of the components will not be affected. The Fire

Protection Program states that the diesel-driven fire pump inspection requires that the pump

and its driver be periodically tested and inspected to ensure that diesel engine subsystems,

including the fuel supply line, can perform their intended functions. The staff finds that this

program will be effective for managing loss of material due to pitting, and crevice corrosion for

copper alloy piping, piping components, piping elements, and heat exchanger components

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exposed to engine jacket cooling water. On this basis, the staff finds that AMR results

addressed by this line item that credit the Fire Protection Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.10 Reduction of Heat Transfer due to Fouling [1]

LRA Table 3.3.1, Item 3.3.1-52, addresses reduction of heat transfer due to fouling for steel,

stainless steel, and copper alloy heat exchanger tubes exposed to closed cycle cooling water in

the auxiliary systems. The LRA credits the Water Chemistry Control-Closed Cooling Water

Program, Water Chemistry Control-Auxiliary Systems Program, or the Fire Protection Program.

The GALL Report recommends AMP XI.M21, "Closed-Cycle Cooling Water System," to

manage this aging effect. The Table 2 AMR line items crediting the Water Chemistry

Control-Auxiliary Systems Program or the Fire Protection Program in the LRA that reference

this Table 1 line item cite Generic Note E, indicating that the AMR line items are consistent with

the GALL Report material, environment, and aging effect, but a different aging management

program is credited.

The LRA states that the AMR line items that credit the Water Chemistry Control-Auxiliary

Systems Program are consistent with the GALL Report which recommends no further

evaluation. These are listed in Table 3.3.2-7 (HVAC system) and Table 3.3.2-13 (Security

Generator). Plant-specific notes are cited: for HVAC, indicating that this component is part of

the chilled water subsystem for the control room HVAC system and that although this

environment does not directly compare with any GALL Report defined environment, it

approximates the GALL Report defined closed cooling water environment; and for the Security

Generator, indicating that the treated water environment is engine jacket cooling water.

The LRA credits the Fire Protection Program for reduction of heat transfer due to fouling for

AMR items in Table 3.3.2-5 in the Fire Protection-Water system. A plant-specific note indicates

that the treated water environment is engine jacket cooling water.

The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and the

Water Chemistry Control - Closed Cooling Water Program and its evaluations are documented

in SER Sections 3.0.3.2.19, and 3.0.3.3.5, respectively. The staff verified that these aging

management programs include activities that are consistent with the recommendations in the

GALL Report Closed-Cycle Cooling Water Chemistry Program to maintain high water purity,

which is effective for managing reduction of heat transfer due to fouling for steel, stainless

steel, and copper alloy heat exchanger tubes exposed to closed cycle cooling water in the

auxiliary systems. The staff confirmed that the One-Time Inspection Program will be used to

verify the effectiveness of the applicant's Water Chemistry Control-Auxiliary Systems Program

and the Water Chemistry Control - Closed Cooling Water Program to manage reduction of heat

transfer due to fouling. On this basis, the staff finds that AMR results addressed by this line

item that credit the Water Chemistry Control-Auxiliary Systems Program or the Water

Chemistry Control-Closed Cooling Water Program are acceptable.

The staff also reviewed the applicant's Fire Protection Program and its evaluation is

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documented in SER Section 3.0.3.2.11. The Fire Protection Program states that the

diesel-driven fire pump inspection requires that the pump and its driver be periodically tested

and inspected to ensure that diesel engine subsystems, including the fuel supply line, can

perform their intended functions. The staff determined that these inspections will manage

reduction of heat transfer due to fouling for steel, stainless steel, and copper alloy heat

exchanger tubes exposed to engine jacket cooling water such that the intended function of the

components will not be affected. On this basis, the staff finds that AMR results addressed by

this line item that credit the Fire Protection Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.11 Loss of Material due to General Corrosion

LRA Table 3.3.1, Item 3.3.1-58, addresses loss of material due to general corrosion for steel

external surfaces exposed to uncontrolled indoor air (external), outdoor air (external), and

condensation (external) in the auxiliary systems. The LRA credits the External Surfaces

Monitoring Program or the Fire Protection Program. The GALL Report recommends

AMP XI.M36, "External Surfaces Monitoring," to manage this aging effect. The Table 2 AMR

line items crediting the Fire Protection Program in the LRA that reference this Table 1 line item

cite Generic Note E, indicating that the AMR line items are consistent with the GALL Report

material, environment, and aging effect, but a different aging management program is credited.

The Fire Protection Program is credited to manage loss of material on the external surfaces of

carbon steel components in the Fire Protection-CO 2 system exposed to indoor air.

The staff reviewed the applicant's External Surfaces Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.9. The staff confirmed that it includes inspections of

external surfaces that are consistent with the recommendations in the GALL Report External

Surfaces Monitoring Program and are appropriate for managing loss of material due to general

corrosion in the auxiliary systems. On this basis, the staff finds that AMR results addressed by

this line item that credit the External Surfaces Monitoring Program are acceptable.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.11. The staff determined that this aging management program includes

periodic inspections and functional tests of the CO 2 fire suppression system, which are

performed at least once every six months to check for signs of degradation. These inspections

include visual inspections of external surfaces of the system components. Since the External

Surfaces Monitoring Program also recommends visual inspections of external surfaces at least

once per refueling cycle, the staff finds the applicant's Fire Protection Program adequate to

manage loss of material for components in the Fire Protection-CO 2-system. The staff finds that

these inspections will manage loss of material due to general corrosion such that the intended

function of the components will not be affected.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report

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3.3.2.1.12 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.3.1, Item 3.3.1-62, addresses loss of material due to pitting and crevice corrosion

for aluminum piping, piping components, and piping elements exposed to raw water in the

auxiliary systems. The LRA credits the One-Time Inspection Program. The GALL Report

recommends AMP XI. M26, "Fire Protection," to manage this aging effect. The Table 2 AMR

line item in the LRA that references this Table 1 line item cites Generic Note E, indicating that

the AMR line item is consistent with the GALL Report material, environment, and aging effect,

but a different aging management program is credited.

In its response to the staff's request to justify the use of the One-Time Inspection Program

instead of the Fire Protection Program recommended by the GALL Report to manage this aging

effect, the applicant stated that, as identified in LRA Table 3.3.1, line Item 62, the only

components to which this GALL Report line item applies are included in-scope under criterion

10 CFR 54.4(a)(2) and are listed in LRA Table 3.3.2-14-13 (Radwaste system). As indicated in

this table, the aluminum component addressed by Table 3.3.1, line Item 62 is a tank in the

radwaste system. The applicant further stated that aluminum is a corrosion resistant material

that is not expected to experience significant loss of material in this environment. As described

in LRA Appendix B, the One-Time Inspection Program will confirm that the loss of material is

not occurring or insignificant such that an aging management program is not warranted for this

component.

The staff reviewed the applicant's One-Time Inspection Program and its evaluation is

documented in SER Section 3.0.3.1.6. The staff determined that it includes inspections that are

consistent with the recommendations in the GALL Report, and that it will be effective to detect

loss of material due to pitting and crevice corrosion for aluminum piping, piping components,

and piping elements exposed to raw water in the auxiliary systems. Based on industry research

and operating experience, the staff recognizes that aluminum is a corrosion resistant material

that is not expected to experience significant loss of material in this environment. Therefore, the

staff determined that the One-Time Inspection Program is appropriate for managing this aging

effect. The staff's review and evaluation of the applicant's One-Time Inspection Program are

On this basis, the staff finds the AMR results for this line item acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.13 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion, and Fouling [1]

LRA Table 3.3.1, Item 3.3.1-68, addresses loss of material due to general, pitting, crevice and

MIC, and fouling for steel piping, piping components, and piping elements exposed to raw water

in the auxiliary systems. The LRA credits the Fire Water System Program or the Fire Protection

Program. The GALL Report recommends AMP XI.M27, "Fire Water System," to manage this

aging effect. The Table 2 AMR line items crediting the Fire Protection Program in the LRA that

reference this Table 1 line item cite Generic Note E, indicating that the AMR line items are

consistent with the GALL Report material, environment, and aging effect, but a different aging

management program is credited. The LRA states that the Fire Protection Program manages

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loss of material for steel components on the fire diesel cooling water system.

The staff reviewed the applicant's Fire Water System Program and its evaluation is

documented in SER Section 3.0.3.2.12. The staff confirmed that it includes activities that are

consistent with the recommendations in the GALL AMP XI.M27. The staff determined that the

applicant's Fire Water System Program includes tests and inspections of fire water system

components that are appropriate for managing loss of material due to general, pitting, crevice

and MIC, and fouling in the auxiliary systems. On this basis, the staff finds that AMR results

addressed by this line item that credit the Fire Water System Program are acceptable.

The staff's evaluation of the applicant's Fire Protection Program is documented in SER

Section 3.0.3.2.11. The staff determined that this aging management program includes

diesel-driven fire pump inspections that require the pump and its driver be periodically tested

and inspected to ensure that diesel engine subsystems can perform their intended functions.

This verifies that the cooling water system, which is a subsystem of the diesel. engine, will

perform its function. The staff finds that these inspections will manage loss of material for steel

components on the fire diesel cooling water system exposed to raw water such that the

intended function of the components will not be affected. On this basis, the staff finds that AMR

results addressed by this line item that credit the Fire Protection Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.14 Loss of Material due to General, Pitting, and Crevice Corrosion [3]

LRA Table 3.3.1, Item 3.3.1-71, addresses loss of material due to general, pitting, and crevice

corrosion for steel piping, piping components, an piping elements exposed to moist air or

condensation (internal). The LRA credits the Periodic Surveillance and Preventive Maintenance

Program or the One-Time Inspection Program. The GALL Report recommends AMP XI.M38,

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to manage

this aging effect. The Table 2 AMR line items that reference this Table 1 line item cite Generic

Note E, indicating that the AMR line items are consistent with the GALL Report material,

environment, and aging effect, but a different aging management program is credited. The LRA

credits this line item for components in the emergency diesel generator system and supporting

subsystems that are exposed to untreated air.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluations are documented in SER Section 3.0.3.3.4. The staff determined that this

program includes inspections of the EDG air intake components using visual and other proven

NDE techniques that are appropriate for managing loss of material due to general, pitting, and

crevice corrosion. The inspections are performed during the periodic system and component

surveillances or during the performance of maintenance activities and any significant loss of

material will be evaluated to determine if corrective actions are required or the frequency of

inspections to be increased. On this basis, the staff finds that AMR results addressed by this

line item that credit the Periodic Surveillance and Preventive Maintenance Program are

acceptable.

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During the audit and review, the staff asked the applicant to clarify how the One-Time

Inspection Program will manage loss of material for steel components exposed to untreated air.

In its response, the applicant stated that the LRA Table 2 line items referencing this Table 1 line

item and crediting the one-time inspection are incorrect. The LRA will be amended to credit the

Periodic Surveillance and Preventive Maintenance Program instead of the one-time inspection

for these line items. In its letter dated February 1, 2007, the applicant amended the LRA

Table 3.3.2-14-41 to credit the Periodic Surveillance and Preventive Maintenance Program for

component types compressor housing, piping, and valve body that compare to GALL line

Item 3.3.1-71. The staff finds this amendment acceptable since the Periodic Surveillance and

Preventive Maintenance Program includes inspections that are acceptable to manage this

aging effect.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.15 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion, Fouling, and Lining/Coating Degradation

LRA Table 3.3.1, Item 3.3.1-76, addresses loss of material due to general, pitting, crevice, and

microbiologically influenced corrosion, fouling, and lining/coating degradation for steel piping,

piping components, and piping elements (without lining/coating or with degraded lining/coating)

exposed to raw water. The LRA credits the Service Water Integrity Program or the Periodic

Surveillance and Preventive Maintenance Program. The GALL Report recommends

AMP XI.M20, "Open-cycle Cooling Water System," to manage this aging effect. The Table 2

AMR line items that reference this Table 1 line item and credit the Periodic Surveillance and

Preventive Maintenance Program cite Generic Note E, indicating that the AMR line items are

consistent with the GALL Report material, environment, and aging effect, but a different aging

management program is credited.

The staff reviewed the applicant's Service Water Integrity Program and its evaluation is

documented in SER Section 3.0.3.2.17. The staff determined that this program includes

activities that are consistent with GALL AMP XI.M20. On this basis, the staff finds that AMR

results addressed by this line item that credit the Service Water Integrity Program are

acceptable.

During the audit and review, the staff asked the applicant to provide the technical justification

for crediting the Periodic Surveillance and Preventive Maintenance Program to manage this

aging effect.

In its response, the applicant stated that the Periodic Surveillance and Preventive Maintenance

Program is credited for components that are not within the scope of the Service Water Integrity

Program. The components for which the Periodic Surveillance and Preventive Maintenance

Program is credited are in the radwaste and plant drains systems and are not exposed to

service water. The raw water environment refers to untreated water, such as plant drains, that

is not service water. The Periodic Surveillance and Preventive Maintenance Program includes

periodic inspection of these components using visual inspection or other NDE techniques that

will detect loss of material.

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The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this

program includes periodic inspections of the radwaste and plant drains system components

using visual and other proven NDE techniques that are appropriate for managing loss of

material. The inspections are performed periodically and any significant loss of material will be

evaluated to determine if corrective actions are required. The staff determined that these

inspections are appropriate to monitor loss of material of radwaste and plant drains system

components. On this basis, the staff finds that AMR results addressed by this line item that

credit the Periodic Surveillance and Preventive Maintenance Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.16 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion, and Fouling [2]

LRA Table 3.3.1, Item 3.3.1-77, addresses loss of material due to general, pitting, crevice, and

microbiologically influenced corrosion, and fouling, for steel heat exchanger components

exposed to raw water. The LRA credits the Service Water Integrity Program or the Periodic

Surveillance and Preventive Maintenance Program. The GALL Report recommends

AMP XI.M20, "Open-Cycle Cooling Water System," to manage this aging effect. The Table 2

AMR line items that references this Table 1 line item and credits the Periodic Surveillance and

Preventive Maintenance Program cites Generic Note E, indicating that the AMR line items are

consistent with the GALL Report material, environment, and aging effect, but a different aging

management program is credited.

The staff reviewed the applicants Service Water Integrity Program and evaluation is

documented in SER Section 3.0.3.2.17. The staff determined that this program includes

activities that are consistent with the Open-Cycle Cooling Water System Program in the GALL

Report. On this basis, the staff finds that AMR results addressed by this line item that credit the

Service Water Integrity Program are consistent with the recommendations in the GALL Report,

and are acceptable.

During the audit and review, the staff asked the applicant to provide the technical justification

for crediting the Periodic Surveillance and Preventive Maintenance Program to manage this

aging effect.

In its response, the applicant stated that the Periodic Surveillance and Preventive Maintenance

Program is credited for components that are not within the scope of the Service Water Integrity

Program. The components for which the Periodic Surveillance and Preventive Maintenance

Program is credited are heat exchanger shells in the plumbing, and sanitary and lab systems

that are not exposed to service water. The raw water environment refers to untreated water,

such as plant drains, that is not service water. The Periodic Surveillance and Preventive

Maintenance Program includes periodic inspection of these components using visual inspection

or other NDE techniques that will detect loss of material.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

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and its evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this

program includes inspections of the heat exchanger shells in the plumbing, sanitary and lab

systems using visual and other proven NDE techniques that are appropriate for managing loss

of material. The inspections are performed periodically and any significant loss of material will

be evaluated to determine if corrective actions are required. The staff determined that these

inspections are appropriate to monitor loss of material of heat exchanger shells in the plumbing,

sanitary and lab systems. On this basis, the staff finds that the AMR results addressed by this

line item that credit Periodic Surveillance and Preventive Maintenance Program is acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.17 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-79, addresses loss of material due to pitting and crevice corrosion

for stainless steel piping, piping components, and piping elements exposed to raw water. The

LRA credits the Service Water Integrity Program, One-Time Inspection Program, or the

Periodic Surveillance and Preventive Maintenance Program. The GALL Report recommends

AMP XI.M20, " Open-Cycle Cooling Water System," to manage this aging effect. The Table 2

AMR line items that reference this Table 1 line item and credit the One-Time Inspection or

Periodic Surveillance and Preventive Maintenance Program cite Generic Note E, indicating that

the AMR line items are consistent with the GALL Report material, environment, and aging

effect, but a different aging management program is credited.

The staff reviewed the applicants Service Water Integrity Program and its evaluation is

documented in SER Section 3.0.3.2.17. The staff determined that this program includes

activities that are consistent with the Open-Cycle Cooling Water System Program in the GALL

Report. On this basis, the staff finds that AMR results addressed by this line item that credit the

Service Water Integrity Program are consistent with the recommendations in the GALL Report,

and are acceptable.

During the audit and review, the staff asked the applicant to provide the technical justification

for crediting the One-Time Inspection Program or the Periodic Surveillance and Preventive

Maintenance Program to manage this aging effect for components in the auxiliary systems.

In its response, the applicant stated that either the One-Time Inspection Program or Periodic

Surveillance and Preventive Maintenance Program is credited for AMR line items in which the

environment of raw water is used to identify untreated water, such as drain water, radwaste

water, ventilation system drain water, potable water, and chemical treatment water. This water

is not treated; however, it is also not service water and the components are not within the scope

of the Service Water Integrity Program. The components for which the Periodic Surveillance

and Preventive Maintenance Program is credited are primarily wetted and the

material/environment is susceptible to aging degradation; therefore, periodic inspections are

required to manage aging. The components for which the One-Time Inspection Program is

credited have material/environment combinations that are not susceptible to aging; therefore a

one-time inspection is appropriate to verify that no significant aging is occurring.

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The staff reviewed the LRA and bases documents and determined that the components

addressed by the AMR line items that credit the Periodic Surveillance and Preventive

Maintenance Program are in the radwaste and plant drains system, and the service water

system. The staff also reviewed the applicant's Periodic Surveillance and Preventive

Maintenance Program and determined that this program includes inspections of components in

the radwaste and drains system, and the service water system, using visual and other proven

NDE techniques that are appropriate for managing loss of material. The inspections are

performed every 10 years for stainless steel drain tanks, and every five years for stainless steel

components used in chemical treatment in the service water system. Any significant loss of

material detected will be evaluated to determine if corrective actions are required. The staff

finds these activities adequate to manage loss of material for these components. On this basis,

the staff finds that the AMR results addressed by this line item that credit the Periodic

Surveillance and Preventive Maintenance Program are acceptable.

The staff also reviewed the LRA and determined that the components addressed by the AMR

line items that credit the One-Time Inspection Program are in the radwaste system, and raw

water treatment system. The staff reviewed the applicant's One-Time Inspection Program and

determined that this program includes inspections of components in the radwaste system and

the raw water treatment system, using visual and other proven NDE techniques that are

appropriate for detecting loss of material. The inspections will be performed during the 10-year

period immediately prior to entering the period of extended operation to confirm that no

significant aging degradation is occurring in these components. Any significant loss of material

detected will be evaluated to determine if corrective actions, including expansion of the

inspection sample size, are required. On this basis, the staff finds that AMR line items

addressed by this line item that credit the One-Time Inspection Program are acceptable.

On the bases of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM appropriately as recommended by the

GALL Report.

3.3.2.1.18 Loss of Material due to Pitting, Crevice, and Microbiologically Influenced Corrosion,

and Fouling

LRA Table 3.3.1, item 3.3.1-81, addresses loss of material due to pitting, crevice, and

microbiologically influenced corrosion for copper alloy piping, piping components, and piping

elements exposed to raw water. The LRA credits the Service Water Integrity Program,

One-Time Inspection Program, or the Periodic Surveillance and Preventive Maintenance

Program. The GALL Report recommends AMP XI.M20, "Open-Cycle Cooling Water System,"

to manage this aging effect. The Table 2 AMR line items that reference this Table 1 line item

and credit the One-Time Inspection or Periodic Surveillance and Preventive Maintenance

Program cite Generic Note E, indicating that the AMR line items are consistent with the GALL

Report material, environment, and aging effect, but a different aging management program is

credited.

The staff reviewed the applicants Service Water Integrity Program and its evaluation is

documented in SER Section 3.0.3.2.17. The staff determined that this program includes

activities that are consistent with the Open-Cycle Cooling Water System Program in the GALL

Report. On this basis, the staff finds that AMR results addressed by this line item that credit the

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Service Water Integrity Program are consistent with the recommendations in the GALL Report,

and are acceptable.

During the audit and review, the staff asked the applicant to provide the technical justification

for crediting the One-Time Inspection Program or the Periodic Surveillance and Preventive

Maintenance Program to manage this aging effect for components in the auxiliary systems. In

its response, the applicant stated that either the One-Time Inspection Program or the Periodic

Surveillance and Preventive Maintenance Program is credited for AMR line items in which the

environment of raw water is used to identify untreated water, such as drain water, radwaste

water, ventilation system drain water, potable water, and chemical treatment water. This water

is not treated; however, it is also not service water and the components are not within the scope

of the Service Water Integrity Program. The components for which, the Periodic Surveillance

and Preventive Maintenance Program is credited are primarily wetted and the

material/environment is susceptible to aging degradation; therefore, periodic inspections are

required to manage aging.

The staff reviewed the LRA and bases documents and determined that the components

addressed by this AMR line items that credit the-Periodic Surveillance and Preventive

Maintenance Program are in the radwaste and plant drains system. The staff also reviewed the

applicant's Periodic Surveillance and Preventive Maintenance Program and determined that this

program includes inspections of components in the radwaste and drains system using visual

and other proven NDE techniques that are appropriate for managing loss of material. The

inspections are performed every 10 years for copper alloy floor drain cleanouts in drain lines.

Any significant loss of material detected will be evaluated to determine if corrective actions are

required. The staff finds these activities adequate to manage loss of material for these

components. On this basis, the staff finds that the AMR results addressed by this line item that

credit the Periodic Surveillance and Preventive Maintenance Program are acceptable.

The staff also reviewed the LRA and bases documents and determined that the components

addressed by this AMR line items that credit the One-Time Inspection Program are in the raw

water treatment system, the plumbing, sanitary and lab system, and the city water system. The

staff reviewed the applicant's One-Time Inspection Program and determined that this program

includes inspections of components in these systems using visual and other proven NDE

techniques that are appropriate for detecting loss of material. The inspections will be performed

during the 10-year period immediately prior to entering the period of extended operation to

confirm that no significant aging degradation is occurring in these components. Any significant

loss of material detected will be evaluated to determine if corrective actions, including

expansion of the inspection sample size, are required. The staff finds these activities

acceptable to manage loss of material for these components since, based on industry research

and operating experience, this material/environment combination is not susceptible to

corrosion. In addition, the components exposed to drains are not continuously wetted, which

further reduces their susceptibility to corrosion. On this basis, the staff finds that AMR results

addressed by this line item that credit the One-Time Inspection Program are acceptable.

3.3.2.1.19 Reduction of Heat Transfer due to Fouling [2]

LRA Table 3.3.1, item 3.3.1-83, addresses reduction of heat transfer due to, fouling for stainless

steel and copper alloy heat exchanger tubes exposed to raw water. The LRA credits the Service

Water Integrity Program, Fire Protection Program, or the Periodic Surveillance and Preventive

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Maintenance (PSPM) Program. The GALL Report recommends AMP XI.M20, " Open-Cycle

Cooling Water System," to manage this aging effect. The Table 2 AMR line items that reference

this Table 1 line item and credit the Fire Protection or Periodic Surveillance and Preventive

Maintenance Program cite Generic Note E, indicating that the AMR line items are consistent

with the GALL Report material, environment, and aging effect, but a different aging

management program is credited.

The staff reviewed the applicants Service Water Integrity Program and its evaluation is

documented in SER Section 3.0.3.2.17. The staff determined that this program includes

activities that are consistent with the Open-Cycle Cooling Water System Program in the GALL

Report. On this basis, the staff finds that AMR results addressed by this line item that credit the

Service Water Integrity Program are consistent with the recommendations in the GALL Report,

and are acceptable.

During the audit and review, the staff asked .the applicant to provide the technical justification

for crediting the Fire Protection Program or the Periodic Surveillance and Preventive

Maintenance Program to manage this aging effect for components in the auxiliary systems. In

its response, the applicant stated that the Periodic Surveillance and Preventive Maintenance

Program is credited to manage fouling in copper alloy heat exchanger tubes for the control

room chiller condenser that are exposed to service water in the HVAC systems. The Periodic

Surveillance and Preventive Maintenance Program is credited since determination of heat

transfer capability, which is necessary to detect fouling, is not performed in the Service Water

Integrity Program. The Fire Protection Program is specified to manage fouling in copper alloy

heat exchanger tubes exposed to system fire water used for fire pump diesel engine cooling.

The diesel fire pump cooling uses fire water from the lake as a cooling source. Testing of the

cooling capacity of the heat exchanger is observed during pump testing in the Fire Protection

Program and manages fouling of these components. The Service Water Integrity Program is

not applicable to fire water used as a heat sink.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this

program includes performance tests of heat exchanger tubes in the HVAC systems that are

appropriate for detecting a loss of heat transfer capability to managing fouling. The

performance tests are performed every 5 years and any significant loss of heat transfer

capability will be evaluated to determine if corrective actions are required. The staff finds these

activities adequate to manage fouling for these components. On this basis, the staff finds that

the AMR results addressed by this line item that credit the Periodic Surveillance and Preventive

Maintenance Program are acceptable.

The staff also reviewed the applicant's Fire Protection Program and its evaluation is

documented in SER Section 3.0.3.2.11. The staff determined that this program includes

performance tests of the diesel fire pump, which include observation of the engine cooling heat

exchanger to determine cooling capacity. Any significant loss of heat transfer capacity detected

will be evaluated to determine if corrective actions are required. The staff finds these activities

acceptable to manage loss of material for these components since, monitoring heat transfer

capacity is an effective means of managing fouling in heat exchanger tubes. On this basis, the

staff finds that AMR results addressed by this line item that credit the Fire Protection Program

are acceptable.

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3.3.2.1.20 AMR Results Identified as Not Applicable

In LRA Table 3.3.1, line items 36, 39, 40, 41, 53, 54, 72, 75, 92, and 95 are identified as "Not

Applicable" since the component/material/environment combination does not exist at JAFNPP.

For each of these line items, the staff reviewed the LRA and the applicant's supporting bases

documents, and confirmed the applicant's claim that the component/material/environment

combination does not exist at JAFNPP. On the basis that JAFNPP does not have the

component/material/ environment combination for these Table 1 line items, the staff finds that

these AMRs are not applicable to JAFNPP.

3.3.2.1.21 AMR Results Identified as Not Used

In LRA Table 3.3.1, line items 42, 61, 63, 65, 66, 67, 73,-74, 80, and 86 are identified as "not

used" since the component/material/environment combination is addressed by:another Table 1

line item. For each of these line items, the staff reviewed the LRA and bases documents and

confirmed that the line item was not used in the LRA. In addition, the staff confirmed that the

aging effects addressed by these line items were addressed by other appropriate Table 1 AMR

line items. On this basis, the staff finds the applicant's identification of these Table 1 AMR line

items as "not used" acceptable.

3.3.2.1.22 Amendment of the LRA - AMR Items for Floor and Roof Drainage,

Nonsafety-Related Components Affecting Safety Related Systems

By letter dated May 17, 2007 (ML0714301850), the applicant amended the LRA to include LRA

Table 3.3.2-14-45, "Floor and Roof Drainage, Nonsafety-Related Components Affecting

Safety-Related Systems-Summary of Aging Management Evaluation," showing AMR items for

the floor and roof drain line system bolting, piping, and valve bodies brought within the scope of

license renewal by that letter.

LRA Table 3.3.2-14-45 shows two AMR items, carbon steel pressure-retaining piping and valve

bodies exposed internally to a raw water environment, for which loss of material was an AERM.

The applicant also claimed for these AMR items consistency with GALL AMR item VII.C1-19

except that it credited the Periodic Surveillance and Preventative Maintenance Program to

manage loss of material in them instead of the Open-Cycle Cooling Water System Program

(GALL AMP XI.M20) recommended by GALL AMR item VII.C1-19 for this aging effect. Hence,

the applicant included these AMR items within the scope of Footnote E for the table.

The recommendations of GALL AMP XI.M20, "Open-Cycle Cooling Water System," apply to

system components that transfer heat from safety-related systems to ultimate heat sinks. GALL

AMP XI.M20 states that it manages aging effects caused by biofouling, corrosion, erosion,

protective coating failures, and silting in these systems or in structures or components serviced

by these systems and that GL 89-13, "Service Water Problems Affecting Safety-Related

Equipment," applies to aging management of such components. GL 89-13 recommends for

these systems and components a condition monitoring program as well as preventive actions

which may include chemical treatment or flushing of raw water systems to mitigate biofouling.

GALL AMP XI.M20 states that visual examination, UT, or eddy current testing techniques may

be acceptable methods for monitoring component surfaces for aging effects.

The piping and valve bodies covered by these AMR items (i.e., floor and roof drain piping and

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valve bodies exposed to raw water) are within the scope of license renewal because their failure

(loss of pressure-retaining integrity) could impact the integrity of SSCs that serve license

renewal functions. The drains are not necessary to support the heat transfer function of the

service water system or the UHS; thus, it is important only to manage aging effects that could

cause loss of structural integrity in such piping and valve bodies. Cracking is not likely, these

drain lines serve only infrequently, and no industry literature indicates IGSCC as an aging effect

of concern for carbon steel components. The only aging effect that could cause a loss of

integrity in these components is loss of material, which could occur if general, pitting, or crevice

corrosion were present.

The applicant credited its Periodic Surveillance and Preventative Maintenance Program to

manage loss of material in the surfaces of floor drain and roof drain piping and valve bodies

,,exposed internally to raw water. This program credits visual or other nondestructive .

examinations of a representative sample of floor drains in the plant to determine whether loss of

material has occurred in these drain lines. These inspection methods are the same as those

recommended in GALL AMP XI.M20, "Open-Cycle Cooling Water System," for management of

loss of material in the pressure boundary components serviced by raw water (i.e., service

water).

Based on this review, the staff finds that it is acceptable to credit the Periodic Surveillance and

Preventative Maintenance Program for these components because the AMP credits the same

examination methods that GALL AMP XI.M20, "Open-Cycle Cooling Water System," would use

if credited for aging management.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing the associated aging effects. On the basis of its review,

the staff concludes that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are indeed consistent with the AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for

the auxiliary systems components. The applicant provided information concerning how it will

manage the following aging effects:

• cumulative fatigue damage

" reduction of heat transfer due to fouling

" cracking due to stress corrosion cracking

" cracking due to stress corrosion cracking and cyclic loading

* hardening and loss of strength due to elastomer degradation

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" reduction of neutron-absorbing capacity and loss of material due to general corrosion

" loss of material due to general, pitting, and crevice corrosion

" loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion

" loss of material due to general, pitting, crevice, microbiologically-influenced corrosion

and fouling

a loss of material due to pitting and crevice corrosion

* loss of material due to pitting, crevice, and galvanic corrosion

, loss of material due to pitting, crevice, and microbiologically-influenced corrosion

,* loss of material due to wear

* loss of material due to cladding breach

, QA for aging management of nonsafey-related components

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. The

staff's evaluation of the aging effects is discussed in the following sections.

3.3.2.2.1 Cumulative Fatigue Damage

The staff reviewed LRA Section 3.3.2.2.1 against the SRP-LR Section 3.3.2.2.1 criteria.

SRP-LR Section 3.3.2.2.1states that Fatigue is a time-limited aging analysis (TLAA) as defined

in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1).

This TLAA is addressed separately in Section 4.3, "Metal Fatigue Analysis," of SRP-LR.

The staff reviewed the applicant's TLAA on Metal Fatigue of Non-Class 1 Components in LRA

Section 4.3.2.

During the audit and review, the applicant clarified that the piping and in-line components in

Table 3.3.2-X including cyclone separators, drain pots, expansion joints, flow elements,

mufflers, orifices, piping, rupture disks, steam traps, strainers, strainer housings, thermowells,

T-quenchers, tubing and valve bodies are identified with a TLAA for fatigue, and are discussed

in LRA Section 4.3.2. These components were designed to the applicable ASME Code

Section III, Section VIII or ANSI B31.1 code. Since the TLAA remains valid per

10CFR54.21(c)(1)(I), no aging management program is required to manage the aging effect.

SER Section 4.3.2.2 documents the staff's review of the applicant's evaluation of this TLAA for

Non-Class 1 components, including non-class 1 portions of the auxiliary systems.

In LRA Section 3.3.2.2.1, the applicant further states that where fatigue damage is identified as

an aging effect requiring management for components with no fatigue design requirements

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(ASME or ANSI codes), the aging effect is managed by inspection. The Periodic Surveillance

and Preventive Maintenance, Fire Protection, and One-Time Inspection Programs will manage

cracking due to fatigue for these components. The staff reviewed each of these AMRs on a

case-by-case basis to confirm that the aging management program credited is appropriate, and

that the evaluation is included in this SER in the section corresponding to the components and

systems addressed.

The staff noted that Table 3.3.1-1, line item 1 addresses cumulative fatigue damage for steel

crane structural girders exposed to air-indoor uncontrolled (external). The LRA states that this

line item was not used since cranes are treated as structural components. The staff confirmed

that cranes are included in LRA Section 3.5 as structural components. The staff's evaluation of

the AMR for cranes is included in Section 3.5 of this SER.

3.3.2•2.2 Reduction of Heat Transfer Due to Fouling

In LRA Section 3.3.2.2.2, the applicant addressed reduction of heat transfer due to fouling. The

applicant stated that this is an aging effect requiring management for stainless steel heat

exchanger tubes exposed to treated water. At JAFNPP there are no stainless steel heat

exchanger tubes exposed to treated water in the auxiliary systems with an intended function of

heat transfer; therefore, this item is not applicable to JAFNPP.

The staff reviewed the LRA and confirmed that there are no stainless steel heat exchanger

tubes exposed to treated water in the auxiliary systems.

On the basis that JAFNPP does not have any components subject to this aging effect, the staff

finds that this further evaluation is not applicable to JAFNPP.

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.3 against the SRP-LR Section 3.3.2.2.3 criteria.

(1) In LRA Section 3.3.2.2.3, Item 1, the applicant addressed cracking due to SCC in the

stainless steel piping, piping components, and piping elements of the BWR standby

liquid control (SLC) system that are exposed to sodium pentaborate solution greater

than 140 OF. The applicant stated that at JAFNPP the sodium pentaborate solution in the

SLC system does not exceed 140°F. Therefore, cracking due to SCC is not an aging

effect requiring management for the SLC system and this item is not applicable to

JAFNPP.

The staff reviewed the LRA and bases documents and confirmed that the sodium

pentaborate solution in the JAFNPP SLC system does not exceed 1400F. Therefore, the

staff determines that cracking due to SCC is not an aging effect requiring management

for the SLC system and that this item is not applicable to JAFNPP.

(2) In LRA Section 3.3.2.2.3, Item 2, the applicant addressed cracking due to SCC in

stainless steel heat exchanger components exposed to treated water greater than

1400 F. The applicant stated that this is an aging effect requiring management at

JAFNPP. For JAFNPP auxiliary systems, these stainless steel heat exchanger

components are managed by the Water Chemistry Control-BWR Program. This

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program monitors parameters and contaminants to ensure that they remain within the

limits specified by the EPRI guidelines. The effectiveness of the Water Chemistry

Control-BWR Program will be confirmed by the One-Time Inspection Program through

an inspection of a representative sample of components crediting this program for

managing cracking using visual and ultrasonic inspection techniques.

SRP-LR Section 3.3.2.2.3, Item 2, states that cracking due to SCC could occur in

stainless steel and stainless clad steel heat exchanger components exposed to treated

water greater than 60 °C (>140 OF). The GALL Report recommends further evaluation of

a plant-specific AMP to ensure that these aging effects are adequately managed.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively; The-staff determined that these

-programs include activities that are consistent-with-recommendations in the GALL

Report, and are adequate to manage cracking due to SCC in stainless steel heat

exchanger components exposed to treated water greater than 1400 F. The Water

Chemistry Control-BWR Program monitors parameters and contaminants to ensure they

remain within the limits specified by the EPRI guidelines, which-will minimize the

susceptibility of these components to cracking due to SCC. On this basis, the staff finds

that the applicant has met the criteria of SRP-LR Section 3.3.2.2.3, Item 2, for further

evaluation.

(3) In LRA Section 3.3.2.2.3, Item 3, the applicant addressed cracking due to SCC in

stainless steel diesel engine exhaust piping exposed to diesel exhaust. The applicant

stated that cracking can occur when moisture collects inside the component when the

diesel is not in operation. At JAFNPP, the stainless steel exhaust components are

oriented vertically, which precludes pooling of water. Therefore, cracking due to SCC is

not an aging effect requiring management for the stainless steel diesel engine exhaust

piping, and this item is not applicable to JAFNPP.

SRP-LR Section 3.3.2.2.3, Item 3, states that cracking due to SCC could occur in

stainless steel diesel engine exhaust piping, piping components, and piping elements

exposed to diesel exhaust. The GALL Report recommends further evaluation of a

plant-specific AMP to ensure that these aging effects are adequately managed.

During the audit and review, the staff asked the applicant to justify why these

components are not inspected to confirm that cracking is not occurring.

In its response, the applicant stated that inspection of the exhaust system components

is included in the Periodic Surveillance and Preventive Maintenance Program; therefore,

inspections will be performed every five years. The applicant committed to amend the

LRA to revise the further evaluation in Section 3.3.2.2.3 to state that the PSPM Program

will verify the absence of cracking in the exhaust system components. In its letter dated

February 1, 2007, the applicant amended the LRA Section 3.3.2.2.3 to state that "This

item is not applicable to JAFNPP." is replaced by "However, the PSPM Program will

verify the absence of cracking in the stainless steel exhaust components." The staff

finds acceptable the applicant's response since periodic inspections performed as part

of the Periodic Surveillance and Preventive Maintenance Program will be effective to

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verify the absence of cracking in these components. On this basis, the staff finds that

the applicant has met the criteria of SRP-LR Section 3.3.2.2.3, Item 3, for further

evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.3. For those line items that apply to LRA Section 3.3.2.2.3,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.4 against the SRP-LR Section 3.3.2.2.4 criteria.

(1) In LRA Section 3.3.2.2.4, Item 1, the applicant addressed cracking due to SCC and

cyclic loading in stainless steel PWR nonregenerative heat exchanger components

exposed to treated borated water greater than 140 OF in the chemical and volume

control system. The applicant stated that JAFNPP is a BWR and does not have a

nonregenerative heat exchanger exposed to treated borated water; therefore, this item

is not applicable to JAFNPP.

The staff finds this section not applicable to JAFNPP because JAFNPP is a BWR plant

and does not have these components.

(2) In LRA Section 3.3.2.2.4, Item 2, the applicant addressed cracking due to SCC and

cyclic loading in stainless steel PWR regenerative heat exchanger components exposed

to treated borated water greater than 140 OF. The applicant stated that JAFNPP is a

BWR and does not have a regenerative heat exchanger exposed to treated borated

water; therefore, this item is not applicable to JAFNPP.

The staff finds this section not applicable to JAFNPP because JAFNPP is a BWR plant

and does not have these components.

(3) In LRA Section 3.3.2.2.4, Item 3, the applicant addressed cracking due to SCC and

cyclic loading in the stainless steel pump casing of PWR high-pressure pumps in the

chemical and volume control system. The applicant stated that JAFNPP is a BWR and

does not have a chemical and volume control system; therefore, this item is not

applicable to JAFNPP.

The staff finds this section not applicable to JAFNPP because JAFNPP is a BWR plant

and does not have these components.

(4) In LRA Table 3.3.1, line item 10, the applicant addressed cracking due to SCC and

cyclic loading in the high-strength steel closure bolting exposed to air with steam or

water leakage in the auxiliary systems. The applicant stated that high-strength steel

bolting is not used in the auxiliary systems at JAFNPP; therefore, this item is not

applicable to JAFNPP.

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The staff noted that this further evaluation was inadvertently omitted from

Section 3.3.2.2.4 of the SRP-LR, Revision 1; however, it is addressed in Table 3.3-1,

line item 10 of the SRP-LR. Consequently, the LRA does not include a separate section

for this further evaluation; however, it is addressed in LRA Table 3.3-1, line item 10,

which is consistent with the SRP-LR.

The staff reviewed the LRA and the supporting documentation and confirmed that high-strength

steel closure bolting is not used in the JAFNPP auxiliary systems. On the basis that JAFNPP

does not use high-strength steel bolting in the auxiliary systems subject to this aging effect, the

staff finds that this further evaluation is not applicable to JAFNPP.

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.3.2.2.5 against the SRP-LR Section 3.3.2.2.5 criteria.

(1) In LRA Section 3.3.2.2.5,lItem 1, the applicant addressed cracking and change in

material properties due to elastomer degradation in elastomer flexible connections of

auxiliary systems and other systems exposed to air - indoor. The applicant stated that

these are aging effects requiring management at JAFNPP. These aging effects are

managed by the Periodic Surveillance and Preventive Maintenance Program. This

program includes visual inspections and physical manipulation of the flexible

connections to confirm that the components are not experiencing any aging that would

affect accomplishing their intended functions.

SRP-LR Section 3.3.2.2.5, Item 1, states that hardening and loss of strength due to

elastomer degradation could occur in elastomer seals and components of heating and

ventilation systems exposed to air - indoor uncontrolled (internal/external). The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that these

aging effects are adequately managed.

The staff reviewed the applicant's PSPM Program and its evaluation is documented in

SER Section 3.0.3.3.4. The staff determined-that this aging management program

includes visual inspections and physical manipulation of elastomeric connections to

confirm that the components are not experiencing any aging that would affect

accomplishing their intended functions. The staff determined that the Periodic

Surveillance and Preventive Maintenance Program includes periodic inspections that are

performed as part of routine plant surveillance and preventive maintenance activities.

These inspections will detect degradation of elastomeric components in a timely manner

such that corrective actions can be taken prior to a loss of component intended function.

On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.5, Item 1, for further evaluation.

(2) In LRA Section 3.3.2.2.5, Item 2, the applicant addressed hardening and loss of

strength due to elastomer degradation in elastomer linings of the filters, valves, and ion

exchangers in spent fuel pool cooling and cleanup systems exposed to treated water.

The applicant stated that, for the auxiliary systems at JAFNPP no credit is taken for any

elastomer linings to prevent loss of material from the underlying carbon steel material.

The material is identified as carbon steel for the aging management review; therefore,

this item is not applicable to JAFNPP.

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SRP-LR Section 3.3.2.2.5, Item 2, states that hardening loss of strength due to

elastomer degradation could occur in elastomer linings of the filters, valves, and ion

exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR) exposed

to treated water or to treated borated water. The GALL Report recommends that a

plant-specific AMP be evaluated to determine and assesses the qualified life of the

linings in the environment to ensure that these aging effects are adequately managed.

The staff reviewed the LRA and bases documents and confirmed that no credit is taken

for any elastomer linings to prevent loss of material from the underlying carbon steel

material. The material is identified as carbon steel for the aging management review and

appropriate aging management programs are credited to manage aging of these

components.

On the basis that JAFNPP does not credit elastomer linings to prevent loss of material

from the underlying carbon steel material any components subject to this aging effect,

the staff finds that this further evaluation is not applicable to JAFNPP.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.5. For those line items that apply to LRA Section 3.3.2.2.5,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.

In LRA Section 3.3.2.2.6, the applicant addressed loss of material and cracking, and reduction

of neutron absorbing capacity for Boral spent fuel storage racks exposed to a treated water

environment. The applicant stated that loss of material and cracking are managed by the Water

Chemistry Control-BWR Program. Reduction of neutron-absorbing capacity is insignificant and

requires no aging management. The potential for aging effects due to sustained irradiation of

Boral was previously evaluated by the staff (BNL-NUREG-25582, dated January 1979;

NUREG-1 787, VC Summer SER, paragraph 3.5.2.4.2, page 3-408) and determined to be

insignificant. Plant operating experience with Boral coupons inspected in 2005 is consistent with

the staffs conclusion and an aging management program is not required for this effect.

SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of

material due to general corrosion could occur in the neutron-absorbing sheets of BWR and

PWR spent fuel storage racks exposed to treated water or to treated borated water. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that these aging

effects are adequately managed.

During the audit and review, the staff asked the applicant for additional information related to

the testing of the Boral coupons and the results.

In its response, the applicant stated that in 2005, nine Boral coupons from JAFNPP spent fuel

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racks were subjected to nondestructive testing. The condition of the coupons included some

localized pitting and blistering of the aluminum skin. The pitting was attributed to residual

carbon steel chips left on the surface of the Boral during assembly of the capsules. The blisters

were attributed to hydrogen formed by reaction between the pool water and internal surfaces of

the aluminum. These conditions did not affect the intended function of the Boral. The areal

densities determined by neutron attenuation measurements exceeded the minimum

as-fabricated values in every case, which confirms that a reduction in neutron absorption

capacity is not occurring. This testing is documented in the JAFNPP condition report.

The staff reviewed condition report and confirmed the applicant's claim that reduction of

neutron absorption is insignificant for the Boral coupons. The staff finds that reduction of

neutron-absorbing capacity is insignificant and requires no aging management.

The staff reviewed-the applicant's Water Chemistry Control-BWR Program and its evaluation is

documented in SER Section 3.0.3.1.10. The staff determined that this program includes

activities that are consistent with recommendations in the GALL Report, and are adequate to

manage loss of material and cracking for Boral spent fuel storage racks exposed to a treated

water environment. The Water Chemistry Control-BWR Program monitors parameters and

contaminants to ensure they remain within the limits specified by the EPRI guidelines, which will

minimize the susceptibility of these components to loss of material and cracking. On this basis,

the staff finds that the applicant has met the criteria of SRP-LR Section 3.3.2.2.6 for further

evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.6. For those line items that apply to LRA Section 3.3.2.2.6,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.7 against the SRP-LR Section 3.3.2.2.7 criteria.

(1) In LRA Section 3.3.2.2.7, Item 1, the applicant addressed loss of material due to

general, pitting, and crevice corrosion in steel piping, piping components, and piping

elements, including the tubing, valves, and tanks in the reactor coolant pump oil

collection system exposed to lubricating oil. The applicant stated that steel piping and

components in auxiliary systems at JAFNPP that are exposed to lubricating oil are

managed by the Oil Analysis Program, which includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. During the past five years, many visual

inspections of components containing lubricating oil have been performed during

corrective and preventive maintenance activities. The visual inspections of these

components would identify degraded conditions such as fouling, corrosion or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one-time inspection to provide confirmation of the

effectiveness of the Oil Analysis Program. The applicant further stated that JAFNPP is a

BWR with an inert containment atmosphere and as a result has no reactor coolant

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pump oil collection system.

SRP-LR Section 3.3.2.2.7, Item 1, states that loss of material due to general, pitting,

and crevice corrosion could occur in steel piping, piping components, and piping

elements, including the tubing, valves, and tanks in the reactor coolant pump oil

collection system, exposed to lubricating oil (as part of the fire protection system). The

existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits, thereby preserving an environment that is not

conducive to corrosion. However, control of lube oil contaminants may not always have

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil

control should be verified to ensure that corrosion is not occurring. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the

effectiveness of the lubricating oil program. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the

period of extended operation. In addition, corrosion may occur at locations in the reactor

coolant pump oil collection tank where water from wash downs may accumulate.

Therefore, the effectiveness of the program should be verified to ensure that corrosion

is not occurring. The GALL Report recommends further evaluation of programs to

manage loss of material due to general, pitting, and crevice corrosion, to 'include

determining the thickness of the lower portion of the tank. A one-time inspection is an

acceptable method to ensure that corrosion is not occurring and that the component's

intended function will be maintained during the period of extended operation.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its response dated February 1, 2007, the applicant amended the LRA

Section 3.2.2.2.7, Item 1 to state "One-time Inspection Program activities will be utilized

to confirm the effectiveness of the Oil Analysis Program." The staff finds that the use of

a one-time inspection to verify the effectiveness of the oil analysis program is consistent

with. the recommendations in the GALL Report, and is acceptable.

The staff reviewed the applicant's Oil Analysis Program and determined that this

program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits. The staff finds that these activities are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to general, pitting, and crevice corrosion for steel piping, piping

components, and piping elements exposed to lubricating oil.

The staff confirmed that since JAFNPP is a BWR with an inert containment atmosphere,

it has no reactor coolant pump oil collection system. Therefore, aging of the tubing,

valves, and tanks in the reactor coolant pump oil collection system are not applicable for

JAFNPP.

The staff finds that the applicant's further evaluation is consistent with the

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recommendations in the SRP-LR. On this basis, the staff finds that the applicant has

met the criteria of SRP-LR Section 3.2.2.2.7, Item 1, for further evaluation.

(2) In LRA Section 3.3.2.2.7, Item 2, the applicant addressed loss of material due to

general, pitting, and crevice corrosion in steel piping, piping components, and piping

elements in the BWR reactor water cleanup and shutdown cooling systems exposed to

treated water. The applicant stated that JAFNPP does not have a separate shutdown

cooling system. Loss of material due to general, pitting, and crevice corrosion in carbon

steel piping and components in other systems exposed to treated water are managed by

the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry

Control-BWR Program will be confirmed by the One-Time Inspection Program through

an inspection of a representative sample of components crediting this program including

susceptible locations such as areas of stagnant flow.

SRP-LR Section 3.3.2.2.7, Item 2, states that loss of material due to general, pitting,

and crevice corrosion could occur in steel piping, piping components, and piping

elements in the BWR reactor water cleanup and shutdown cooling systems exposed to

treated water. The existing AMP relies on monitoring and control of reactor water

chemistry to manage the aging effects of loss of material from general, pitting, and

crevice corrosion. However, high concentrations of impurities at crevices and locations

of stagnant flow conditions could cause general, pitting, or crevice corrosion. Therefore,

the effectiveness of the chemistry control program should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage loss of material from general, pitting, and crevice corrosion to

verify the effectiveness of the water chemistry program. A one-time inspection of select

components at susceptible locations is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the

period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in the GALL

Report, and are adequate to manage loss of material due to general, pitting, and crevice

corrosion in steel piping, piping components, and piping elements exposed to treated

water. The staff finds that the applicant's further evaluation is consistent with the

recommendations in the SRP-LR. On this basis, the staff finds that the applicant has

met the criteria of SRP-LR Section 3.3.2.2.7, Item 2, for further evaluation.

(3) In LRA Section 3.3.2.2.7, Item 3, the applicant addressed loss of material due to general

(steel only) pitting and crevice corrosion for steel and stainless steel diesel exhaust

piping, piping components, and piping elements exposed to diesel exhaust. The

applicant stated that this aging effect for carbon steel and stainless steel diesel exhaust

piping and components exposed to diesel exhaust in the emergency diesel generator

and security generator systems is managed by the Periodic Surveillance and Preventive

Maintenance Program. This program uses visual and other NDE techniques to manage

loss of material for these components. The carbon steel and stainless steel diesel

exhaust piping and components in the fire protection system are managed by the Fire

Protection Program. The Fire Protection Program uses visual inspections of diesel

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exhaust piping and components to manage loss of material. These inspections in the

PSPM and Fire Protection Program will manage the aging effect of loss of material such

that the intended function of the components will not be affected.

SRP-LR Section 3.3.2.2.7, Item 3, states that loss of material due to general (steel only)

pitting and crevice corrosion could occur for steel and stainless steel diesel exhaust

piping, piping components, and piping elements exposed to diesel exhaust. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that these

aging effects are adequately managed.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance

Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff

determined that this program uses visual and other NDE techniques to manage loss of

material for carbon steel and stainless steel diesel exhaust piping and components in

the fire protection system. The staff also reviewed the applicant's Fire Protection

Program and its evaluation is documented in SER Section 3.0.3.2.11. The staff

determined that this program includes visual inspections of diesel exhaust piping and

components to manage loss of material. The staff finds that the inspections performed

in the Periodic Surveillance and Preventive Maintenance Program and Fire Protection

Program will manage the aging effect of loss of material such that the intended function

of the components will not be affected. On this basis, the staff finds that the applicant

has met the criteria of SRP-LR Section 3.3.2.2.7, Item 3, for further evaluation.

Based on the Programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.7. For those line items that apply to LRA Section 3.3.2.2.7,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.

In LRA Section 3.3.2.2.8, the applicant addressed loss of material due to general, pitting,

crevice, and MIC for carbon steel (with or without coating or wrapping) piping and components

buried in soil in the auxiliary systems at JAFNPP. The applicant stated that this aging effect is

managed by the Buried Piping and Tanks Inspection Program. This program will include (a)

preventive measures to mitigate corrosion and (b) inspections to manage the effects of

corrosion on the pressure-retaining capability of buried carbon steel components. Buried

components will be inspected when excavated during maintenance. An inspection will be

performed within ten years of entering the period of extended operation, unless an opportunistic

inspection occurred within this ten-year period. This program will manage the aging effect of

loss of material such that the intended function of the components will not be affected.

SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, crevice corrosion,

and MIC could occur for steel (with or without coating or wrapping) piping, piping components,

and piping elements buried in soil. The buried piping and tanks inspection program relies on

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industry practice, frequency of pipe excavation, and operating experience to manage the effects

of loss of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the

buried piping and tanks inspection program should be verified to evaluate an applicant's

inspection frequency and operating experience with buried components, thus ensuring that loss

of material would not be occurring.

The staff reviewed the applicant's Buried Piping and Tanks Inspection Program and its

evaluation is documented in SER Section 3.0.3.2.1. The staff determined that this program

includes opportunistic or focused inspections of buried components that are consistent with the

recommendations in the GALL Report, and are adequate to manage loss of material due to

general, pitting, crevice, and MIC for carbon steel (with or without coating or wrapping) piping

and components buried in soil. The staff confirmed that inspections will be performed both

during the 10-year period immediately prior to the period of extended operation, as well as

during the 10-year period after entering the period of extended operation, which is consistent

with the recommendations in the GALL Report.

During the audit and review, the staff asked the applicant for additional information on JAFNPP

operating experience with buried components.

In its response, the applicant stated that a search of condition reports from the early 1990s to

present identified only one incident in which a leak in a buried hydrogen supply line was

evaluated. The root cause was determined to be poor application of the protective coating on

the line, and was not aging related. Corrective actions were taken to replace the degraded

section of buried piping. In addition, the applicant stated that during the period from the mid

1990s to present, several fire protection system buried valves were excavated and none

showed any evidence of corrosion. Based on a review of JAFNPP plant-specific operating

experience, the staff confirmed that opportunistic inspections of buried components are

performed at JAFNPP, and loss of material on buried components that would lead to a loss of

intended function during the period of extended operation is not occurring. The staff finds that

the JAFNPP operating experience supports the use of the Buried Piping and Tanks Inspection

Program as an effective means of managing aging of buried components.

Based on the program identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.8. For those line items that apply to LRA Section 3.3.2.2.8,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically- Influenced

Corrosion and Fouling

The staff reviewed LRA Section 3.3.2.2.9 against the SRP-LR Section 3.3.2.2.9 criteria.

(1) In LRA Section 3.3.2.2.9, Item 1, the applicant addressed loss of material due to

general, pitting, crevice, and MIC for carbon steel piping and components exposed to

fuel oil. The applicant stated that this is an aging effect requiring management at

JAFNPP and these components are managed by the Diesel Fuel Monitoring Program.

This program includes sampling and monitoring of fuel oil quality to ensure they remain

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within the limits specified by the ASTM standards. Maintaining parameters within limits

ensures that significant loss of material will not occur. Ultrasonic inspection of storage

tank bottoms where water and contaminants accumulate will be performed to confirm

the effectiveness of the Diesel Fuel Monitoring Program. In addition, inspections of

components during the previous five years at JAFNPP have confirmed the effectiveness

of this program in lieu of a one-time inspection program, such that loss of material will

not affect the intended functions of these components.

SRP-LR Section 3.3.2.2.9, Item 1, states that loss of material due to general, pitting,

crevice, MIC, and fouling could occur for steel piping, piping components, piping

elements, and tanks exposed to fuel oil. The existing AMP relies on the fuel oil

chemistry program for monitoring and control of fuel oil contamination to manage loss of

material due to corrosion or fouling. Corrosion or fouling may occur at locations where

contaminants accumulate. The effectiveness of the fuel oil chemistry control should be

verified to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage loss of material due to general, pitting, crevice, MIC,

and fouling to verify the effectiveness of the fuel oil chemistry program. A one-time

inspection of selected components at susceptible locations is an acceptable method to

ensure that corrosion is not occurring and that the component's intended function will be

maintained during the period of extended operation.

The staff reviewed the applicant's Diesel Fuel Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.8. The staff determined that this program includes

periodic sampling and analysis of diesel fuel to maintain contaminants within acceptable

limits. The program also includes periodic draining, cleaning, and inspection of tanks to

remove contaminants and verify the absence of significant degradation. The staff finds

that these activities are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to general, pitting, crevice, and MIC for

carbon steel piping and components exposed to fuel oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the inspections that are being credited in lieu of

a one-time inspection include visual inspections of components at the most susceptible

locations for components containing fuel oil, such as the bottom of tanks. If the

inspection finds unacceptable results, they will be evaluated under the site corrective

action program and the inspection population will be expanded. These inspections are

performed periodically as part of routine maintenance. The staff finds that the use of a

routine, periodic inspections and the performance of UT inspections of tank bottoms that

are consistent with the one-time inspection program described in the GALL Report is

acceptable to verify the effectiveness of the Diesel Fuel Monitoring Program.

The staff finds that the applicant's further evaluation is consistent with the

recommendations in the SRP-LR. On this basis, the staff finds that the applicant has

met the criteria of SRP-LR Section 3.3.2.2.9, Item 1, for further evaluation.

(2) In LRA Section 3.3.2.2.9, Item 2, the applicant addressed loss of material due to

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general, pitting, crevice and MIC for carbon steel heat exchanger components exposed

to lubricating oil. The applicant stated that this is an aging effect requiring management

in the auxiliary systems at JAFNPP and is managed by the Oil Analysis Program. This

program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits, thereby preserving an environment that is not

conducive to corrosion. During the past five years, many visual inspections of

components containing lubricating oil have been performed during corrective and

preventive maintenance activities. The visual inspections of these components would

identify degraded conditions such as fouling, corrosion or cracking that could be

attributed to an ineffective Oil Analysis Program. These past inspections at JAFNPP

serve in lieu of a one-time inspection to provide confirmation of the effectiveness of the

Oil Analysis Program.

SRP-LR Section 3.3.2.2.9,, Item 2, states that loss of materialdue to general, pitting,

crevice, MIC, and fouling could occur for steel heat exchanger components exposed to

lubricating oil. The existing AMP relies on the periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lube oil program. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion is not occurring and that the component's intended function will be maintained

during the period of extended operation.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its response dated February 1, 2007, the applicant amended the LRA

Section 3.2.2.2.7, Item 1 to state "One-time Inspection Program activities will be utilized

to confirm the effectiveness of the Oil Analysis Program." The staff finds that the use of

a one-time inspection to verify the effectiveness of the oil analysis program is consistent

with the recommendations in the GALL Report, and is acceptable.

The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection

Program its evaluations are documented in SER Sections 3.0.3.2.14 and 3.0.3.1.6,

respectively. The staff determined that the Oil Analysis Program includes periodic

sampling and analysis of lubricating oil to maintain contaminants within acceptable

limits. The staff finds that these activities are consistent with the recommendations in

the GALL Report, and are adequate to manage loss of material due to general, pitting,

crevice and MIC for carbon steel heat exchanger components exposed to lubricating oil.

The staff's finds that the One-Time Inspection Program activities are also consistent

with the GALL report.

The staff finds that the applicant's further evaluation is consistent with the

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recommendations in the SRP-LR. On this basis, the staff finds that the applicant has

met the criteria of SRP-LR Section 3.2.2.2.9, Item 2, for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.9. For those line items that apply to LRA Section 3.3.2.2.9,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.10 against the SRP-LR Section 3.3.2.2.10 criteria.

(1) In LRA Section 3.3.2.2.10, Item 1, the applicant addressed loss of material due to pitting

and crevice corrosion in steel piping with elastomer lining or stainless steel cladding that

is exposed to treated water and treated borated water if the cladding or lining is

degraded. The applicant stated that for the auxiliary systems at JAFNPP, no credit is

taken for elastomer linings or stainless steel cladding to prevent loss of material from

the underlying carbon steel material when exposed to treated water or treated borated

water; the material is identified as carbon steel for the aging management review. The

Water Chemistry Control-BWR Program manages loss of material in steel components

exposed to treated water. The effectiveness of the program will be confirmed by the

One-Time Inspection Program.

SRP-LR Section 3.3.2.2.10, Item 1, states that loss of material due to pitting and crevice

corrosion could occur in BWR and PWR steel piping with elastomer lining or stainless

steel cladding that are exposed to treated water and treated borated water if the

cladding or lining is degraded. The existing AMP relies on monitoring and control of

reactor water chemistry to manage the aging effects of loss of material from pitting and

crevice corrosion. However, high concentrations of impurities at crevices and locations

of stagnant flow conditions could cause pitting, or crevice corrosion. Therefore, the

effectiveness of the chemistry control program should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage loss of material from pitting and crevice corrosion to verify the

effectiveness of the water chemistry program. A one-time inspection of select

components at susceptible locations is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the

period of extended operation.

The staff reviewed the LRA and the bases documents and confirmed that no credit is

taken for any elastomer linings in steel piping to prevent loss of material from the

underlying carbon steel material. The material is identified as carbon steel for the aging

management review and appropriate aging management programs are credited to

manage aging of these components.

The staff also reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

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programs include activities that are consistent with the recommendations in the GALL

Report, and are adequate to manage loss of material due to pitting and crevice

corrosion in steel piping that are exposed to treated water. On this basis, the staff finds

that the applicant has met the criteria of SRP-LR Section 3.3.2.2.10, Item 1, for further

evaluation.

(2) In LRA Section 3.3.2.2.10, Item 2, the applicant addressed loss of material due to pitting

and crevice corrosion for stainless steel and aluminum piping, piping components,

piping elements, and for stainless steel and steel with stainless steel cladding heat

exchanger components exposed to treated water. The applicant stated that in the

auxiliary systems at JAFNPP there are no aluminum components exposed to treated

water. Loss of material due to pitting and crevice corrosion for stainless steel piping and

components and for, stainless steel heat exchanger components, exposed to treated

water in the auxiliary systems at JAFNPP is managed by the Water Chemistry

Control-BWR Program. The effectiveness of the Program will be confirmed by the

One-Time Inspection Program through an inspection of a representative sample of

components crediting this program including susceptible locations such as areas of

stagnant flow.

SRP-LR Section 3.3.2.2.10, Item 2, states that loss of material due to pitting and crevice

corrosion could occur for stainless steel and aluminum piping, piping components,

piping elements, and for stainless steel and steel with stainless steel cladding heat

exchanger components exposed to treated water. The existing AMP relies on monitoring

and control of reactor water chemistry to manage the aging effects of loss of material

from pitting and crevice corrosion. However, high concentrations of impurities at

crevices and locations of stagnant flow conditions could cause pitting, or crevice

corrosion. Therefore, the effectiveness of the chemistry control program should be

verified to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage loss of material from pitting and crevice corrosion to

verify the effectiveness of the water chemistry program. A one-time inspection of select

components at susceptible locations is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the

period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Time Inspection Program, and determined that these programs include activities

that are consistent with the recommendations in the GALL Report, and are adequate to

manage loss of material due to pitting and crevice corrosion for stainless steel piping

and components, and for stainless steel heat exchanger components exposed to treated

water. On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.10, Item 2, for further evaluation.

(3) In LRA Section 3.3.2.2.10, Item 3, the applicant addressed loss of material due to pitting

and crevice corrosion for copper alloy components exposed to condensation (external)

in the HVAC and other systems. The applicant stated that this aging effect is managed

by the External Surfaces Monitoring, Periodic Surveillance and Preventive Maintenance

(PSPM), and Service Water Integrity Programs. The External Surfaces Monitoring

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Program includes a periodic visual inspection. The PSPM and Service Water Integrity

Programs include visual inspections and other NDE techniques to manage loss of

material of the components. These inspections will manage the aging effect of loss of

material such that the intended function of the components will not be affected.

SRP-LR Section 3.3.2.2.10, Item 3, states that loss of material due to pitting and crevice

corrosion could occur for copper alloy HVAC piping, piping components, and piping

elements exposed to condensation (external). The GALL Report recommends further

evaluation of a plant-specific AMP to ensure that these aging effects are adequately

managed.

The staff reviewed the applicant's External Surfaces Monitoring Program, Periodic

Surveillance and Preventive Maintenance Program and Service Water Integrity Program

and its evaluations are documented in SER Sections 3.0.3.2.9, 3.0.3.3.4, and

3.0.3.2.17, respectively. The staff determined that the External Surfaces Monitoring

Program includes a periodic visual inspection of components that will be effective for

detecting loss of material. Also, the Periodic Surveillance and Preventive Maintenance

Program and Service Water Integrity Programs include visual inspections and other

NDE techniques that will be effective to detect loss of material. The staff's review and

evaluation of the applicant's External Surfaces Monitoring Program, Periodic

Surveillance and Preventive Maintenance Program and Service Water Integrity Program

The staff finds that the aging management programs credited are acceptable to manage

the aging effect of loss of material such that the intended function of the components

will not be affected. On this basis, the staff finds that the applicant has met the criteria of

SRP-LR Section 3.3.2.2.10, Item 3, for further evaluation.

(4) In LRA Section 3.3.2.2.10, Item 4, the applicant addressed loss of material due to pitting

and crevice corrosion for copper alloy components exposed to lubricating oil in auxiliary

systems at JAFNPP. The applicant stated that this aging effect is managed by the Oil

Analysis Program, which includes periodic sampling and analysis of lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment that

is not conducive to corrosion. During the past five years, many visual inspections of

components containing lubricating oil have been performed during corrective and

preventive maintenance activities. The visual inspections of these components would

identify degraded conditions such as fouling, corrosion or cracking that could be

attributed to an ineffective Oil Analysis Program. These past inspections at JAFNPP

serve in lieu of a one-time inspection to provide confirmation of the effectiveness of the

Oil Analysis Program.

SRP-LR Section 3.3.2.2.10, Item 4, states that loss of material due to pitting and crevice

corrosion could occur for copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP relies on the periodic sampling and analysis

of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection

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of selected components at susceptible locations is an acceptable method to ensure that

corrosion is not occurring and that the component's intended function will be maintained

during the period of extended operation.

The staff reviewed the applicant's Oil Analysis Program and determined that this

program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits. The staff finds that these activities are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to pitting and crevice corrosion for copper alloy piping, piping components,

and piping elements exposed to lubricating oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its response dated February 1, 2007, the applicant amended the LRA

Section 3.3.2.2.10, Item 4 to state "One-time Inspection Program activities will be

utilized to confirm the effectiveness of the Oil Analysis Program." The staff finds that the

use of a one-time inspection to verify the effectiveness of the oil analysis program is

consistent with the recommendations in the GALL Report, and is acceptable.

The staff finds that the applicant's further evaluation is consistent with the

recommendations in the SRP-LR. On this basis, the staff finds that the applicant has

met the criteria of SRP-LR Section 3.2.2.2.10, Item 4, for further evaluation.

(5) In LRA Section 3.3.2.2.10, Item 5, the applicant addressed loss of material due to pitting

and crevice corrosion for aluminum piping and components and stainless steel

components exposed to condensation. The applicant stated that this is an aging effect

requiring management for HVAC and other systems at JAFNPP. The Bolting Integrity,

External Surfaces Monitoring, Periodic Surveillance and Preventive Maintenance and

Service Water Integrity Programs will manage loss of material in aluminum or stainless

steel components exposed internally or externally to condensation. These programs

include a periodic visual inspection and the PSPM Program includes other NDE

techniques to manage loss of material of the components.

SRP-LR Section 3.3.2.2.10, Item 5, states that loss of material due to pitting and crevice

corrosion could occur for HVAC aluminum piping, piping components, and piping

elements and stainless steel ducting and components exposed to condensation. The

GALL Report recommends further evaluation of a plant-specific AMP to ensure that

these aging effects are adequately managed.

The staff reviewed the applicant's Bolting Integrity Program, External Surfaces

Monitoring Program, Periodic Surveillance and Preventive Maintenance Program and

Service Water Integrity Program and its evaluations are documented in SER

Sections 3.0.3.2.20, 3.0.3.2.9, 3.0.3.3.4, and 3.0.3.2.17, respectively. The staff

determined that the Bolting Integrity and External Surfaces Monitoring Programs include

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a periodic visual inspection of components that will be effective for detecting loss of

material. Also, the Periodic Surveillance and Preventive Maintenance Program and

Service Water Integrity Program include visual inspections and other NDE techniques

that will be effective to detect loss of material. The staff.finds that the aging

management programs credited are acceptable to manage the aging effect of loss of

material such that the intended function of the components will not be affected. On this

basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.10, Item 5, for further evaluation.

(6) In LRA Section 3.3.2.2.10, Item 6, the applicant addressed loss of material due to pitting

and crevice corrosion for copper alloy fire protection system piping, piping components,

and piping elements exposed to internal condensation. The applicant stated that at

JAFNPP, there are no copper alloy components exposed to condensation in the fire

protection systems. However, this item can be applied to copper alloy components

exposed to internal condensation in other systems. The Periodic Surveillance and

Preventive Maintenance Program and One-Time Inspection Program will manage loss

of material or confirm the aging effect is absent or insignificant in copper alloy

components exposed internally to untreated air, which is equivalent to condensation,

through the use of visual inspections or other NDE techniques.

SRP-LR Section 3.3.2.2.10, Item 6, states that loss of material due to pitting and crevice

corrosion could occur for copper alloy fire protection system piping, piping components,

and piping elements exposed to internal condensation. The GALL Report recommends

further evaluation of a plant-specific AMP to ensure that these aging effects are

adequately managed.

During the audit and review, the staff asked the applicant to clarify when the Periodic

Surveillance and Preventive Maintenance Program will be used to manage this aging

effect, and when the One-Time Inspection Program will be used.

In its response, the applicant stated that the Periodic Surveillance and Preventive

Maintenance Program will be used for components requiring periodic inspection to

manage aging effects. The One-Time Inspection Program is used for components

where insignificant aging effects are expected, and confirmation that no significant aging

is occurring is required. The staff finds this approach to be consistent with the function

of these programs, and is acceptable.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance

Program and determined that it includes proven monitoring techniques, acceptance

criteria, corrective actions, and administrative controls that will be effective for managing

loss of material due to pitting and crevice corrosion for copper alloy piping, piping

components, and piping elements exposed to internal condensation. The staff also

reviewed the applicant's One-Time Inspection Program and determined that it includes

proven NDE inspection techniques that will be effective to verify that significant loss of

material is not occurring. The staff finds that the programs credited are acceptable to

manage this aging effect for the components addressed by this further evaluation. On

this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.10, Item 6, for further evaluation.

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(7) In LRA Section 3.3.2.2.10, Item 7, the applicant addressed loss of material due to pitting

and crevice corrosion for stainless steel piping, piping components, and piping elements

exposed to soil. The applicant stated that at JAFNPP, there are no stainless steel piping

components exposed to soil in the auxiliary systems; therefore, this item is not

applicable to JAFNPP.

The staff reviewed the LRA and basis document and confirmed that there are no

stainless steel piping components exposed to soil in the auxiliary systems. On the basis

that JAFNPP has no stainless steel piping components exposed to soil in the auxiliary

systems, the staff finds this section not applicable to JAFNPP.

(8) In LRA Section 3.3.2.2.10, Item 8, the applicant addressed loss of material due to pitting

-and crevice corrosion for stainless steel piping, piping components, and piping elements

of the BWR standby liquid control system that are exposed to sodium pentaborate

solution. The applicant stated that this aging effect is managed at JAFNPP by the Water

Chemistry Control-BWR Program. The effectiveness of the Water Chemistry

Control-BWR Program will be confirmed by the One-Time Inspection Program through

an inspection of a representative sample of components crediting this program including

susceptible locations such as areas of stagnant flow.

SRP-LR Section 3.3.2.2.10, Item 8, states that loss of material due to pitting and crevice

corrosion could occur for stainless steel piping, piping components, and piping elements

of the BWR standby liquid control system that are exposed to sodium pentaborate

solution. The existing AMP relies on monitoring and control of water chemistry to

manage the aging effects of loss of material due to pitting and crevice corrosion.

However, high concentrations of impurities at crevices and locations of stagnant flow

conditions could cause loss of material due to pitting and crevice corrosion. Therefore,

the GALL Report recommends that the effectiveness of the water chemistry control

program should be verified to ensure this aging is not occurring. A one-time inspection

of select components at susceptible locations is an acceptable method to ensure that

loss of material due to pitting and crevice corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and

One-Tirhe Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in the GALL

Report, and are adequate to manage loss of material due to pitting and crevice

corrosion for stainless steel piping, piping components, and piping elements of the BWR

standby liquid control system that are exposed to sodium pentaborate solution. On this

basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.10, Item 8, for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.10. For those line items that apply to LRA Section 3.3.2.2.10,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

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required by 10 CFR 54.21(a)(3).

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

In LRA Section 3.3.2.2.11, the applicant addressed loss of material due to pitting, crevice, and

galvanic corrosion for copper alloy piping, piping components, and piping elements exposed to

treated water. The applicant stated that this aging effect is managed by the Water Chemistry

Control-BWR Program. The effectiveness of the program will be confirmed by the One-Time

Inspection Program through an inspection of a representative sample of components crediting

this program including susceptible locations such as areas of stagnant flow.

SRP-LRýSection 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic

corrosion could occur for copper alloy piping, piping components, and piping elements exposed

to treated water. Therefore, the GALL Report recommends that the effectiveness of the water

chemistry control program should be verified to ensure this aging is not occurring. A one-time

inspection of select components at susceptible locations is an acceptable method to ensure that

loss of material due to pitting and crevice corrosion is not occurring and that the component's

intended function will be maintained during the period of extended operation.

The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time

Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.10 and

3.0.3.1.6, respectively. The staff determined that these programs include activities that are

consistent with the recommendations in the GALL Report, and are adequate to manage loss of

material due to pitting, crevice, and galvanic corrosion for copper alloy piping, piping

components, and piping elements exposed to treated water.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.11. For those line items that apply to LRA Section 3.3.2.2.11,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.3.2.2.12 against the SRP-LR Section 3.3.2.2.12 criteria.

(1) In LRA Section 3.3.2.2.12, Item 1, the applicant addressed loss of material due to

pitting, crevice, and MIC in stainless steel, aluminum, and copper alloy piping, piping

components, and piping elements exposed to fuel oil. The applicant stated that this is an

aging effect requiring management at JAFNPP and these components are managed by

the Diesel Fuel Monitoring Program. There are no aluminum components exposed to

fuel oil in the auxiliary systems. The Diesel Fuel Monitoring Program includes sampling

and monitoring of fuel oil quality to ensure it remains within the limits specified by the

ASTM standards. Maintaining parameters within limits ensures that significant loss of

material will not occur. Inspections of components during the previous five years at

JAFNPP have confirmed the effectiveness of this program in lieu of a one-time

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inspection program such that loss of material will not affect the intended functions of

these components.

SRP-LR Section 3.3.2.2.12, Item 1, states that loss of material due to pitting, crevice,

and MIC could occur in stainless steel, aluminum, and copper alloy piping, piping

components, and piping elements exposed to fuel oil. The existing AMP relies on the

fuel oil chemistry program for monitoring and control of fuel oil contamination to manage

loss of material due to corrosion. However, corrosion may occur at locations where

contaminants accumulate and the effectiveness of fuel oil chemistry control should be

verified to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage corrosion to verify the effectiveness of the fuel oil

chemistry control program. A one-time inspection of selected components at susceptible

locations is an acceptable method to ensure that corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

operation.

The staff reviewed the applicant's Diesel Fuel Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.8. The staff determined that this program includes

periodic sampling and analysis of diesel fuel to maintain contaminants within acceptable

limits. The program also includes periodic draining, cleaning, and inspection of tanks to

remove contaminants and verify the absence of significant degradation. The staff finds

that these activities are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to pitting, crevice, and MIC in stainless

steel and copper alloy piping, piping components, and piping elements exposed to fuel

oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that routine periodic inspections that are being

credited in lieu of a one-time inspection include visual inspections of components at the

most susceptible locations for components containing fuel oil, such as the bottom of

tanks. If the inspection finds unacceptable results, they will be evaluated under the site

corrective action program and the inspection population will be expanded. These

inspections are performed periodically. The staff finds that the use of routine, periodic

inspections that are consistent with the one-time inspection program described in the

GALL Report is acceptable to verify the effectiveness of the Diesel Fuel Monitoring

Program. On this basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.12, Item 1, for further evaluation.

(2) In LRA Section 3.3.2.2.12, Item 2, the applicant addressed loss of material due to

pitting, crevice, and MIC in stainless steel piping, piping components, and piping

elements exposed to lubricating oil. The applicant stated that this aging effect is

managed by the Oil Analysis Program which includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. During the past five years, many visual

inspections of components containing lubricating oil have been performed during

corrective and preventive maintenance activities. The visual inspections of these

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components would identify degraded conditions such as fouling, corrosion or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one-time inspection to provide confirmation of the

effectiveness of the Oil Analysis Program.

SRP-LR Section 3.3.2.2.12, Item 2, states that loss of material due to pitting, crevice,

and MIC could occur in stainless steel piping, piping components, and piping elements

exposed to lubricating oil. The existing program relies on the periodic sampling and

analysis of lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment that is not conducive to corrosion. However, control of lube

oil contaminants may not always have been adequate to preclude corrosion. Therefore,

the effectiveness of lubricating oil control should be verified to ensure that corrosion is

not occurring. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection

of selected components at susceptible locations is an acceptable method to ensure that

corrosion is not occurring and that the component's intended function will be maintained

during the period of extended operation.

-The staff reviewed the applicant's Oil Analysis Program and determined that this

program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits. The staff finds that these activities are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to pitting, crevice, and MIC in stainless steel piping, piping components,

and piping elements exposed to lubricating oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its response dated February 1, 2007, the applicant amended the LRA

Section 3.3.2.2.12, Item 2 to state,"One-time Inspection Program activities will be

utilized to confirm the effectiveness of the Oil Analysis Program." The staff finds that the

use of a one-time inspection to verify the effectiveness of the oil analysis program is

consistent with the recommendations in the GALL Report, and is acceptable. On this

basis, the staff finds that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.12, Item 2, for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.3.2.2.12. For those line items that apply to LRA Section 3.3.2.2.12,

the staff determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.13 Loss of Material Due to Wear

In LRA Section 3.3.2.2.13, the applicant addressed loss of material due to wear in the

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elastomer seals and components exposed to air indoor uncontrolled (internal or external). The

applicant stated that wear is the removal of surface layers due to relative motion between two

surfaces. At JAFNPP, in the auxiliary systems, this specific aging effect for elastomers is not

applicable since the expansion joints are fixed at both ends and do not contact any other

components such that wear could occur. Where the aging effects of change in material

properties and cracking are identified for elastomer components, they are managed by the

Periodic Surveillance and Preventive Maintenance Program. This item is not applicable to

JAFNPP auxiliary systems.

The staff reviewed the system descriptions in the LRA, along with the system design basis

documents, and confirmed that there are no elastomeric components that are subject to wear in

the JAFNPP auxiliary systems. On the basis that JAFNPP does not have elastomeric

components subject to this aging effect, the staff finds that this further evaluation is not

applicable to JAFNPP.

3.3.2.2.14 Loss of Material Due to Cladding Breach

In LRA Section 3.3.2.2.14, the applicant addressed loss of material due to cladding breach for

PWR steel charging pump casings with stainless steel cladding exposed to treated borated

water. The applicant stated that JAFNPP is a BWR and has no charging pumps; therefore, this

item is not applicable to JAFNPP.

The staff finds this item not applicable to JAFNPP because JAFNPP is a BWR plant and does

not have charging pumps.

3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staffs evaluation of the applicant's QA program.

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

Summary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-13

and 3.3.2-14-1 through 3.3.2-14-44, the staff reviewed additional details concerning the results

of the AMRs for material, environment, AERM, and AMP combinations that are not consistent

with the GALL Report, or that are not addressed in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-13, 3.3.2-14-5, 3.3.2-14-6, 3.3.2-14-9, 3.3.2-14-11,

3.3.2-14-12, 3.3.2-14-13, 3.3.2-14-15, 3.3.2-14-18, 3.3.2-14-23 through 3.3.2-14-41,

3.3.2-14-43, and 3.3.2-14-44, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information concerning how the

aging effects will be managed. Specifically, Note F indicates that the material for the AMR line

item component is not evaluated in the GALL Report. Note G indicates that the environment for

the AMR line item component and material is not evaluated in the GALL Report. Note H

indicates that the aging effect for the AMR line item component, material, and environment

combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified

in the GALL Report for the line item component, material, and environment combination is not

applicable. Note J indicates that neither the component nor the material and environment

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combination for the line item is evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

3.3.2.3.1 Standby Liquid Control System Summary of Aging Management Evaluation -

LRA Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the

SLC system component groups.

The staff noted that LRA*Table 3.2.2-1 includes an AMR line item to address stainless steel

tanks in the SLC system exposed to air-indoor (internal). The AMR line item states that there

are no aging mechanisms or effects for this material/ environment combination. The AMR line

item cites Generic Note G, which indicates that the environment is not addressed in the GALL

Report for this component and material combination. Also, based on current industry research

and operating experience, the staff recognizes that this material/ environment combination is

not susceptible to significant aging degradation. However, the staff noted that the GALL Report

does address other components constructed of stainless steel that are exposed to air,

indoor-uncontrolled for which no aging effect is noted (e.g., Item EP-18 in Table V.F). In

addition, based on industry operating experience, the staff recognizes that this

material/environment combination is not susceptible to significant aging degradation. The staff

reviewed the JAFNPP plant-specific operating experience with components in the auxiliary

systems containing this material/environment combination and confirmed that no aging effects

that would lead to the loss of intended function have been experienced. On this basis, the staff

finds this AMR acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.3.2.3.2 Service Water Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the

service water systems component groups, and determined that the applicant did not include

any AMR results with Generic Notes F through J involving material, environment, AERMs, and

AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.3 Emergency Diesel Generator System Summary of Aging Management Evaluation -

LRA Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the

emergency diesel generator system component groups.

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The staff noted that LRA Table 3.3.2-3 includes AMR line items to address an aluminum

lubricator housing and motor housing in the EDG system exposed to air-untreated (internal).

The AMR line items state that there are no aging mechanisms or effects for these

material/environment combinations. The AMR line items cite Generic Note G, which indicates

that the environment is not addressed in the GALL Report for this component and material

combination.

In its response to the staffs inquiry regarding plant-specific operating experience for this

material/environment combination, the applicant stated that a documented review of the past

five years of operating experience did not identify any aging effects for components in the

auxiliary systems with these material and environment combinations. The GALL Report

identified other components constructed of aluminum in an indoor uncontrolled air environment

exhibit no aging effect and that the component or structure will therefore remain capable of

performing its intended functions consistent with the CLB for the period of extended operation.

Aluminum has an excellent resistance to corrosion when exposed to humid air (an uncontrolled

indoor environment). The aluminum oxide film is bonded strongly to its surface and that film, if

damaged, reforms immediately in most environments. On a surface freshly abraded and then

exposed to air, the oxide film is only 5 to 10 nanometers thick but is highly effective in

protecting the aluminum from further corrosion. For this reason, the staff finds that aluminum

exposed to indoor uncontrolled air environment does not require aging management.

The staff reviewed the applicant's plant-specific operating experience with components in the

auxiliary systems containing this material and environment combination and confirmed that no

aging effects that would lead to the loss of intended function have been experienced. On this

basis, the staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address aluminum valve

bodies in the EDG system exposed to lubricating oil (internal). The AMR line item states that

loss of material will be managed for this component under the Oil Analysis Program. The AMR

line item cites Generic Note G, which indicates that the environment is not addressed in the

GALL Report for this component and material combination. The staff reviewed the applicant's

Oil Analysis Program and its evaluation is documented in SER Section 3.0.3.2.14. The staff

determined that this program includes periodic sampling and analysis to maintain lube oil purity,

which is effective to manage loss of material.

In its response to the staffs inquiry regarding the use of one-time inspections to confirm the

effectiveness of the Oil Analysis Program, the applicant stated that inspection activities will be

added to the One-Time Inspection Program to verify the effectiveness of the Oil Analysis

Program, and applicable LRA sections will be amended. In its letter dated February 1, 2007, the

applicant amended LRA Section B13.21 to state that "Internal surfaces of components exposed

to lube oil" implemented by One-time inspection activity will verify the effectiveness of the oil

analysis program by confirming that unacceptable cracking, loss of material, and fouling is not

occurring to the Program Description section table of activities." The staff finds these activities

acceptable to manage loss of material for aluminum valve bodies exposed to lubricating oil

(internal). On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address aluminum heat

exchanger fins exposed to air-indoor (external). The AMR line item credits the Periodic

Surveillance and Preventive Maintenance Program to manage fouling for this component. The

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AMR cites Generic Note H, which indicates that this aging effect is not addressed in the GALL

Report for this component, material, and environment combination. The staff reviewed the

applicant's Periodic Surveillance and Preventive Maintenance Program and its evaluation is

documented in SER Section 3.0.3.3.4. The staff determined that this program includes activities

to perform EDG system heat exchanger maintenance and inspections, which include testing of

heat exchanger performance and inspection of external surfaces to manage loss of material

and fouling. The staff determined that these activities are adequate to manage fouling for

aluminum heat exchanger fins exposed to air-indoor (external).On this basis, the staff finds the

AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes AMR line items to address copper alloy heat

exchanger tubes exposed to air-indoor (external) in the EDG systems. The AMR line items

credit the Periodic Surveillance and Preventive Maintenance Program to manage fouling and

loss of material-wear for these components. The AMR line items cite Generic Note G, which

indicates that the environment is not addressed in the GALL Report for this component and

material combination. The staff reviewed the applicant's Periodic Surveillance and Preventive

Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff

determined that this program includes activities to perform EDG heat exchanger chiller

maintenance and inspection which includes testing of EDG heat exchanger performance and

inspection of tube external surfaces to manage loss of material and fouling. The staff

determined that these activities are adequate to manage loss of material-wear and fouling for

copper alloy heat exchanger tubes exposed to air-indoor (external). On this basis, the staff finds

the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address copper alloy heat

exchanger tubes exposed to treated water (external) in the EDG system. The AMR credits the

Service Water Integrity Program to manage loss of material-wear for these components. The

AMR cites Generic Note H, which indicates that this aging effect is not addressed in the GALL

Report for this component, material, and environment combination. The staff reviewed the

applicant's Service Water Integrity Program and its evaluation is documented in SER

Section 3.0.3.2.17. The staff determined that this program includes periodic inspections per the

requirements of GL 89-13, including eddy current testing, for heat exchangers to detect aging

degradation.

In its response to the staffs inquiry, the applicant stated that the heat exchangers crediting the

Service Water Integrity Program for aging management are cooled by the service water system

and are therefore inspected per the requirements of GL 89-13 by the Service Water Integrity

Program which manages the loss of material due to wear occurring on the external surfaces of

the tubes by eddy current testing. The staff determined that these activities are adequate to

manage loss of material-wear for copper alloy heat exchanger tubes exposed to treated water

(external). On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address copper alloy heat

exchanger tubes exposed to lubricating oil (external). The AMR line item credits the Heat

Exchanger Monitoring Program to manage loss of material-wear for these components. The

AMR line item cites Generic Note H, which indicates that this aging effect is not addressed in

the GALL Report for this component, material, and environment combination. The staff

reviewed the applicants Heat Exchanger Monitoring Program and its evaluation of the

applicant's Heat Exchanger Monitoring Program'is documented in SER Section 3.0.3.3.1. The

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staff determined that this program includes eddy current testing of a representative sample of

heat exchanger tubes to detect aging degradation. If degradation is found, an evaluation is

performed to determine if corrective actions are necessary. The staff finds that these activities

are adequate to manage loss of material-wear for heat exchanger tubes exposed to lubricating

oil in the auxiliary systems since eddy current testing is a proven technique to detect wall

thinning in tubes. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address a copper alloy

strainer exposed to air-untreated (external) in the EDG system. The AMR line item states that

there are no aging mechanisms or effects for this material and environment combination. The

AMR cites Generic Note G, which indicates that the environment is not addressed in the GALL

Report for this component and material combination. In its response dated April 24, 2007, the

applicant revised LRA Table 3.3.2-3 to state that the component/material combination is

consistent with the GALL Report line item VII.G-9 (AP-78) and the applicant's Periodic

Surveillance and Preventive Maintenance Program will be used to manage the loss of material

aging effect. The staff reviewed the Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.4. The applicant's Periodic

Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the

criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that

manage aging effects not managed by other AMPs. The preventive maintenance and

surveillance testing activities are generally implemented through repetitive tasks or routine

monitoring of plant operations. On this basis, the staff finds that loss of material of copper alloy

strainer exposed to air-untreated (external) in the EDG system will be adequately managed

using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff

finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes AMR line items to address stainless steel filter

housings and valve bodies in the EDG system exposed to air-untreated (internal). The AMR line

items state that there are no aging mechanisms or effects for these material/environment

combinations. The AMR line items cite Generic Note G, which indicates that this environment is

not addressed in the GALL Report for this component and material combination. A

plant-specific Note "301" is included in the LRA indicating that the environment for this

component location is similar to an indoor air environment. The staff noted that the GALL

Report does address other components constructed of stainless steel that are exposed to air,

indoor-uncontrolled for which no aging effect is noted (e.g., Item EP-1 8 in Table V.F). In

addition, the staff reviewed the applicant's plant-specific operating experience with components

in the EDG system containing these material/environment combinations and confirmed that no

aging effects that would lead to the loss of intended function have been experienced. On this

basis, the staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-3 includes AMR line items to address stainless steel filter

strainers in the EDG system exposed to lubricating oil (internal and external). The AMR line

items credit the Oil Analysis Program to manage cracking of these components. The AMR line

items cite Generic Note G, which indicates that the environment is not addressed in the GALL

Report for this component and material combination. The staff reviewed the applicant's Oil

Analysis Program and its evaluation is documented in SER Section 3.0.3.2.14. The staff

determined that this program includes activities to manage cracking of stainless steel strainers

exposed to lubricating oil (internal and external).

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In its response to the staffs inquiry to describe how the aging effect will be managed, the

applicant stated that the Oil Analysis Program maintains oil systems free from contaminants

thereby preserving an environment that is not conducive to loss of material, cracking, or fouling.

Oil sampling frequencies are based on vendor recommendations, accessibility during plant

operation, equipment importance, and previous test results. On this basis, the staff finds the

AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-3 includes an AMR line item to address elastomer duct

flexible connections in the EDG system exposed to air-indoor (internal). The AMR line item

states that there are no aging mechanisms or effects for this material and environment

combination. GALL Report volume 2, Item VII.F1-7 is cited which recommends a plant-specific

aging management program. The AMR cites Generic Note I, which indicates that the aging

effect in the GALL Report for this component, material, and environment combination is not

applicable. A plant-specific note in the AMR states that changes of material properties and

cracking in elastomers are the result of ultra-violet light or elevated temperature greater than

950 F. However, the staff noted that elastomer duct flexible connections exposed to similar

environments in other systems have been identified as being susceptible to aging and requiring

aging management.

In its response to the staffs inquiry, the applicant responded that this AMR line item refers to

the inner surface only of the EDG intake air duct flexible connection, which is neither exposed

to temperature greater than 95 OF nor ultra-violet light. The exterior of this component, however,

is susceptible to aging and is included in LRA Table 3.3.2.3 with the Periodic Surveillance and

Preventive Maintenance Program credited to manage aging of this component. The staff finds

the applicant's explanation acceptable since the inside surface of the flexible connector is not

exposed to ultra-violet light or elevated temperature; therefore, the inside surface of the

elastomer is not expected to degrade significantly. In addition, the outside surface of the

connector will be inspected under the Periodic Surveillance and Preventive Maintenance

Program ; therefore, degradation of the connector will be detected. On this basis, the staff finds

the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-3 includes AMR line items for carbon steel mufflers and

piping and stainless steel expansion joints exposed to EDG exhaust gas (internal). The AMR

line items state that cracking-fatigue of these components is managed as a TLAA - metal

fatigue. The AMR line items for the stainless steel expansion joint cites Generic Note G, which

indicates that this environment is not in the GALL Report for this component and material

combination. The AMR line items for the carbon steel mufflers and piping cite Generic Note H,

which indicates that this aging effect is not addressed in the GALL Report for this component,

material, and environment combination. TLAAs are evaluated in Section 4.3 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.3.2.3.4 Fuel Oil System Summary of Aging Management Evaluation - LRA Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the

fuel oil system component groups.

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The staff noted that LRA Table 3.3.2-4 includes an AMR line item to address loss of material for

stainless steel bolting in the Fuel Oil system exposed to air-outdoor (external). The Bolting

Integrity Program is credited to manage this aging effect. The AMR line item cites Generic

Note G, which indicates that the environment is not addressed in the GALL Report for this

component and material combination. The staff reviewed the applicant's Bolting Integrity

Program and its evaluation is documented in SER Section 3.0.3.2.20. The staff determined that

it includes inspections of bolting exterior surfaces that are effective for detecting a loss of

material for this component. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.3.2-4 includes AMR line items to address aluminum flame

arrestors in the Fuel Oil system exposed to air-outdoor (external) and air-outdoor (internal). The

AMR line items state that there are no aging mechanisms or effects for this

material/environment combination. The AMR line items cite Generic Note G, which indicates

that the environment is not addressed in the GALL Report for this component and material

combination.

In its response to the staffs inquiry about its operating experience, the applicant stated that no

aging effects have been identified in the past for components with this material and

environment combination and that this is consistent with industry (EPRI TR-1010639) operating

experience. The staff noted that aluminum has an excellent resistance to corrosion when

exposed to a humid air (outdoor environment). The aluminum oxide film is bonded strongly to

its surface and, if damaged, reforms immediately in most environments. On a surface freshly

abraded and then exposed to air, the oxide film is only 5 to 10 nanometers thick but is highly

effective in protecting the aluminum from corrosion. Therefore, aluminum exposed to an

outdoor air environment does not have any applicable aging effect. The staff reviewed the

JAFNPP plant-specific operating experience with components in the auxiliary systems

containing this material/environment combination and confirmed that no aging effects that

would lead to the loss of intended function have been experienced. On this basis, the staff finds

the AMR results for these line items acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 Fire Protection - Water System Summary of Aging Management Evaluation -

LRA Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the

fire protection-water system component groups.

The staff noted that LRA Table 3.3.2-5 includes an AMR line item to address stainless steel

bolting in the fire protection water systems exposed to air-outdoor (external). The AMR line item

states that there are no aging mechanisms or effects for this material/ environment

combination. The AMR line item cites Generic Note G, which indicates that the environment is

not addressed in the GALL Report for this component and material combination. In its response

dated April 24, 2007, the applicant revised LRA Table 3.3.2-5 to state that the loss of material is

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the aging effect for stainless steel bolting in the fire protection water systems exposed to

air-outdoor (external) and the Bolting Integrity Program will be used to manage this aging effect.

The staff reviewed the applicant's Bolting Integrity Program and its evaluation is documented in

SER Section 3.0.3.2.20. The staff determined that the applicant's Bolting Integrity Program is

consistent with the GALL Report and it requires periodic visual and inservice inspections to

manage the loss of material. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.3.2-5 includes AMR line items to address cracking-fatigue of

stainless steel expansion joints, gray cast iron turbocharger housings, and carbon steel

mufflers, valves, and piping, in the fire protection water system exposed to exhaust gas

(internal). The AMR line items credits the Fire Protection Program to manage this aging effect.

The AMR line items cite Generic Note H, which indicates that this aging effect is not addressed

in the GALL Report for this component, material, and environment combination. The staff

reviewed the applicant's Fire Protection Program and determined that it includes periodic

testing and inspection of the diesel driven fire pump to ensure that the engine and its

subsystems are functioning properly. The staff finds that these inspections will be effective for

detecting cracking for components exposed to exhaust gas. On this basis, the staff finds the

AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-5 includes an AMR line item to address loss of

material-wear for copper alloy heat exchanger tubes in the fire protection water system exposed

to raw water (external). The AMR line item credits the Fire Protection Program to manage this

aging effect. The AMR line item cites Generic Note H, which indicates that this aging effect is

not addressed in the GALL Report for this component, material, and environment combination.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.11. The staff determined that it includes periodic testing and inspection of

the diesel driven fire pump to ensure that the engine and its subsystems are functioning

properly. The staff finds that these inspections will be effective for detecting loss of material in

the heat exchanger tubes. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.3.2-5 includes an AMR line item to address loss of material for

aluminum heater housings in the fire protection water system exposed to treated water

(internal). The AMR line item credits the Fire Protection Program to manage this aging effect.

The AMR line item cites Generic Note G, which indicates that the environment is not addressed

in the GALL Report for this component and material combination. The AMR line item also

includes a plant-specific note that states that the treated water is engine jacket cooling water.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.11. The staff determined that it includes periodic testing and inspection of

the diesel driven fire pump to ensure that the engine and its subsystems are functioning

properly. The staff finds that these inspections will be effective for detecting loss of material in

the heater housings. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-5 includes AMR line items to address loss of material for

carbon steel nozzles, strainer housings, tanks, valves, and piping in the fire protection water

system exposed to fire protection foam (internal). The AMR line items credit the Fire Water

System Program to manage this aging effect. The AMR line items cites Generic Note G, which

indicates that the environment is not addressed in the GALL Report for this component and

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material combination. The staff reviewed the applicant's Fire Protection Program and its

evaluation is documented in SER Section 3.0.3.2.12. The staff determined that it includes

periodic testing and inspection of the water-based fire protection systems, including nozzles,

strainers, tanks, valves, and piping, in accordance with applicable National Fire Protection

Association codes and standards to ensure functionality of all systems. The staff finds that

these inspections will be effective for detecting loss of material in the nozzles. On this basis, the

staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-5 includes an AMR line item to address copper alloy

nozzles in the fire protection water systems exposed to air-indoor (internal). The AMR line item

states that there are no aging mechanisms or effects for this material/ environment

combination. The AMR line item cites Generic Note G, which indicates that the environment is

not addressed in the GALL Report for this component and material combination. The staff notes

that copper alloy greater than 15-percent zinc in air-indoor internal environment has no aging

effect. This conclusion is based on the fact that comprehensive tests conducted over a 20-year

period under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure as cited in the Metals Handbook, Volume 13, "Corrosion" (American

Society for Metals International, 1987). Also, based on industry research and operating

experience, the staff recognizes that this material/environment combination is not susceptible to

significant aging degradation. The staff reviewed the JAFNPP plant-specific operating

experience with components in the auxiliary systems containing this material/environment

combination and confirmed that no aging effects that would lead to the loss of intended function

have been experienced. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.3.2-5 includes AMR line items to address loss of material for

stainless steel strainers and copper alloy valve bodies in the fire protection water system

exposed to fire protection foam (internal). The AMR line items credit the Fire Water System

Program to manage this aging effect. The AMR line items cite Generic Note G, which indicates

that the environment is not addressed in the GALL Report for this component and material

combination. The staff reviewed the applicant's Fire Water System Program and its evaluation

is documented in SER Section 3.0.3.2.12. The staff determined that it includes periodic testing

and inspection of the water-based fire protection systems, including strainers and valves, in

accordance with applicable National Fire Protection Association codes and standards to ensure

functionality of all systems. The staff finds that these inspections will be effective for detecting

loss of material in these components. On this basis, the staff finds the AMR results for these

line items acceptable.

The staff noted that LRA Table 3.3.2-5 includes an AMR line item to address loss of material

due to selective leaching of copper alloy valve bodies in the fire protection water system

exposed to fire protection foam (internal). The AMR line item credits the Selective Leaching

Program to manage this aging effect. The AMR line item cites Generic Note G, which indicates

that the environment is not addressed in the GALL Report for this component and material

combination. The staff reviewed the applicant's Selective Leaching Program and its evaluation

is documented in SER Section 3.0.3.1.7. The staff determined that it includes a one-time testing

and hardness measurement of components susceptible to selective leaching to determine

whether selective leaching is occurring. If selective leaching is detected, corrective actions will

be taken. The staff finds that these inspections and hardness measurements will be effective

for detecting loss of material due to selective leaching in these components. On this basis, the

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staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.6 Fire Protection - CO2 System Summary of Aging Management Evaluation -

LRA Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the

fire protection-CO2 system component groups.

The staff noted that LRA Table 3.3.2-6 includes AMR line items to address copper alloy and

stainless steel tubing and valve bodies exposed to air-indoor. The AMR line items state that

there are no aging mechanisms or effects for these material/environment combinations. The

AMR line items cite Generic Note G, which indicates that the environment is not addressed in

the GALL Report for this component and material combination. Based on industry operating

experience, the staff recognizes that these material/environment combinations are not

susceptible to significant aging degradation.

The staff also noted that stainless steels are highly resistant to corrosion in dry atmospheres in

the absence of corrosive species (which would be reflective of indoor uncontrolled air), as cited

in the Metals Handbook, Volumes 3 (p. 65) and 13 (p. 555) (Ninth Edition, American Society for

Metals International, 1980 and 1987). Components are not subject to moisture in a dry air

environment (and indoor uncontrolled air would have limited humidity and condensation).

Therefore, Stainless steel in an indoor, uncontrolled air environment exhibits no aging effect,

and the component or structure will remain capable of performing its intended functions

consistent with the CLB for the period of extended operation. For copper alloy greater than

15-percent zinc in air-indoor internal environment does not have any aging effect based on the

fact that comprehensive tests conducted over a 20-year period under the supervision of ASTM

have confirmed the suitability of copper and copper alloys for atmospheric exposure as cited in

Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).

The staff reviewed the JAFNPP plant-specific operating experience with components in the

auxiliary systems containing these material/environment combinations and confirmed that no

aging effects that would lead to the loss of intended function have been experienced. On this

basis, the staff finds the AMR results for these line items acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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3.3.2.3.7 Heating, Ventilation, and Air Conditioning Systems Summary of Aging Management

Evaluation - LRA Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the

heating, ventilation, and air conditioning systems component groups.

The staff noted that LRA Table 3.3.2-7 includes AMR line items to address stainless steel filter

housings, heat exchanger housings, orifices, piping, valve bodies, tubing, and pump casings

exposed to air-indoor (internal). The AMR line items state that there are no aging mechanisms

or effects for these material/environment combinations. The AMR line items cite Generic

Note G, which indicates that the environment is not addressed in the GALL Report for this

component and material combination. Based on current industry research and operating

experience, the staff recognizes that this material/environment combination is not susceptible to

.significant-aging degradation. The staff also noted that stainless steels are highly resistant to

corrosion in dry atmospheres in the absence of corrosive species (which would be reflective of

indoor uncontrolled air), as cited in Metals Handbook, Volumes 3 (p. 65) and 13 (p. 555) (Ninth

Edition, American Society for Metals International, 1980 and 1987). Components are not

subject to moisture in a dry air environment (and indoor uncontrolled air would have limited

humidity and condensation). Therefore, stainless steel in an indoor, uncontrolled air

environment exhibits no aging effect, and the component or structure will remain capable of

performing its intended functions consistent with the CLB for the period of extended operation.

On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-7 includes AMR line items to address copper alloy valve

bodies and tubing exposed to air-indoor (internal). The AMR line items state that there are no

aging mechanisms or effects for these material/environment combinations. The AMR line items

cite Generic Note G, which indicates that the environment is not addressed in the GALL Report

for this component and material combination. The staff also noted that copper alloy greater than

15-percent zinc in air-indoor internal environment does not have any aging effect based on the

fact that comprehensive tests conducted over a 20-year period under the supervision of ASTM

have confirmed the suitability of copper and copper alloys for atmospheric exposure as cited in

Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).

The staff reviewed the JAFNPP plant-specific operating experience with components in the

auxiliary systems containing this material/environment combination and confirmed that no aging

effects that would lead to the loss of intended function during the period of extended operation

have been experienced. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.3.2-7 includes an AMR line item to address nickel alloy heat

exchanger tubesheets exposed to gas (internal). The AMR line item states that there is no

aging mechanisms or effect for this material/environment combination. The AMR line item cites

Generic Note G, which indicates that the environment is not addressed in the GALL Report for

this component and material combination. Based on industry operating experience, the staff

recognizes that this material/environment combination is not susceptible to significant aging

degradation. The staff also noted that the GALL Report does address other components

constructed of nickel alloy that are exposed to air, indoor-uncontrolled for which no aging effect

is noted (e.g., Item RP-03 in Table IV.E). Since the gas environment addressed in this AMR line

item is inert gas, such as carbon dioxide or nitrogen, it is not expected to be more severe than

uncontrolled indoor air; therefore, no aging effects are expected for nickel alloy exposed to gas.

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The staff reviewed the JAFNPP plant-specific operating experience with components in the

auxiliary systems containing this material/environment combination and confirmed that no aging

effects that would lead to the loss of intended function have been experienced. On this basis,

the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-7 includes an AMR line item to address loss of material for

stainless steel heat exchanger housings exposed to air-outdoor (external). The AMR line item

credits the External Surfaces Monitoring Program to manage loss of material for these

components. The AMR line item cites Generic Note H, which indicates that this aging effect is

not addressed in the GALL Report for this component, material, and environment combination.

The staff reviewed the applicant's External Surfaces Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.9. The staff determined that this program includes periodic

inspections of component external surfaces to detect aging degradation. The staff determined

that these activities are adequate to manage loss of material for stainless steel heat exchanger

housings exposed to air-outdoor (external). On this basis, the staff finds the AMR results forthis

line item acceptable.

The staff noted that LRA Table 3.3.2-7 includes AMR line items to address copper alloy heat

exchanger tubes exposed to condensation (external) or gas (external) in the HVAC systems.

The AMR line items credit the Service Water Integrity Program to manage loss of material-wear

and fouling for these components. The AMR line items cite Generic Note G, which indicates

that the environment is not addressed in the GALL Report for this component and material

combination, or Generic Note H, which indicates that this aging effect is not addressed in the

GALL Report for this component, material, and environment combination. The staff reviewed

the applicant's Service Water Integrity Program and its evaluation is documented in SER

Section 3.0.3.2.17. The staff determined that this program includes periodic inspections as per

the requirements of GL 89-13, including eddy current testing, for heat exchangers to detect

aging degradation.

In its response to the staffs inquiry, the applicant stated that the heat exchangers crediting the

Service Water Integrity Program for aging management are control room chiller condensers

that use emergency service water as a heat sink and are therefore inspected per the

requirements of GL 89-13 by the Service Water Integrity Program. The staff determined that

these activities are adequate to manage loss of material-wear and fouling for copper alloy heat

exchanger tubes exposed to condensation (external) or gas (external). On this basis, the staff

finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-7 includes an AMR line item to address aluminum heat

exchanger fins exposed to condensation (external). The AMR line item credits the Service

Water Integrity Program to manage fouling for this component. The AMR line item cites Generic

Note H, which indicates that this aging effect is not addressed in the GALL Report for this

component, material, and environment combination. The staff reviewed the applicant's Service

Water Integrity Program and its evaluation is documented in SER Section 3.0.3.2.17. The staff

determined that this program includes activities to visually inspect components (heat exchanger

fins) or verify the heat transfer capability of safety-related heat exchangers cooled by service

water.

In its response to the staffs inquiry, the applicant stated that the heat exchangers referred to in

this AMR line item are room coolers that are cooled by service water and are therefore included

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in their Service Water Integrity Program. These heat exchangers are either visually inspected or

performance tested to detect fouling. The staff also determined that these activities are

adequate to manage fouling for aluminum heat exchanger fins exposed to condensation

(external). On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.3.2-7 includes AMR line items to address copper alloy heat

exchanger tubes exposed to condensation (external) in the HVAC systems. The AMR line items

credit the Periodic Surveillance and Preventive Maintenance Program to manage fouling and

loss of material-wear for these components. The AMR line items for fouling of copper alloy heat

exchanger tubes cite Generic Note G, which indicates that the environment is not addressed in

the GALL Report for this component and material combination. The AMR line items for loss of

material-wear of copper alloy heat exchanger tubes cites Generic Note H, which indicates that

this aging effect is not addressed in the GALL Report for this component, material, and

environment combination. The staff reviewed the applicants Periodic Surveillance and

Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4.

The staff determined that this program includes activities to perform HVAC chiller maintenance

and inspection which includes testing of HVAC chiller performance and inspection of tube

external surfaces to manage loss of material and fouling. The staff also determined that these

activities are adequate to manage loss of material-wear and fouling for copper alloy heat

exchanger tubes exposed to condensation (external). On this basis, the staff finds the AMR

results for these line items acceptable.

The staff noted that LRA Table 3.3.2-7 includes AMR line items to address copper alloy heat

exchanger tubes exposed to treated water (external) in the HVAC systems. The AMR line items

credit the Periodic Surveillance and Preventive Maintenance Program to manage loss of

material-wear for this component. The AMR line items cite Generic Note H, which indicates that

this aging effect is not addressed in the GALL Repct for this component, material, and

environment combination.

In its response to the staffs inquiry as to why the heat exchanger monitoring or water chemistry

programs were not used to manage this aging effect, the applicant stated that this AMR line

item refers to an evaporator and a water chemistry program alone would not be sufficient to

manage loss of material due to wear on the external tube surfaces. The applicant further stated

that the Periodic Surveillance and Preventive Maintenance Program was incorrectly credited,

and instead the Heat Exchanger Monitoring Program should be credited for loss of material due

to wear. The LRA will be amended to credit the Heat Exchanger Monitoring Program for these

AMR line items. In its letter dated February 1, 2007, the applicant amended the LRA

Table 3.3.2-7 to state: "In the line items for heat exchanger (tubes) / Copper alloy / Gas (ext) /

Loss of material - wear, "Periodic Surveillance and Preventive Maintenance" Program is

changed to "Heat Exchanger Monitoring" Program." The staff reviewed the applicant's Heat

Exchange Monitoring Program and its evaluation is documented in SER Section 3.0.3.3.1. The

staff determined that it includes eddy current testing, which is a proven technique to detect and

manage loss of material for heat exchangers in the HVAC systems. The staff also determined

that these activities are adequate to manage loss of material-wear for copper alloy heat

exchanger tubes exposed to treated water (external). On this basis, the staff finds the AMR

results for these line items acceptable.

The staff noted that LRA Table 3.2.2-7 includes an AMR line item to address aluminum heat

exchanger fins exposed to condensation (external). The AMR line item credits the Periodic

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Surveillance and Preventive Maintenance Program to manage fouling for this component. The

AMR line item cites Generic Note H, which indicates that this aging effect is not addressed in

the GALL Report for this component, material, and environment combination. The staff

reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and its

evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this program

includes activities to perform HVAC chiller maintenance and inspection, which include testing of

HVAC chiller performance and inspection of external surfaces to manage loss of material and

fouling. The staff also determined that these activities are adequate to manage fouling for

aluminum heat exchanger fins exposed to condensation (external). On this basis, the staff finds

the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 Containment Purge, Containment Atmosphere Dilution and Post-Accident Sampling

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the

containment purge, containment atmosphere dilution, and post-accident sampling systems

component groups.

The staff noted that LRA Table 3.3.2-8 includes AMR line items to address stainless steel and

aluminum components in the containment purge, containment atmosphere dilution and

post-accident sampling systems exposed to liquid nitrogen (internal). The AMR line items state

that there is no aging mechanisms or effect for this material/environment combination. The

AMR line items cite Generic Note G, which indicates that the environment is not addressed in

the GALL Report for this component and material combination. Based on current industry

research and operating experience, the staff recognizes that this material/environment

combination is not susceptible to significant aging degradation. The staff noted that nitrogen is

an inert material that does not react with other materials; therefore, it is not expected to result in

degradation of stainless steel or aluminum, which are themselves corrosion resistant materials.

The staff reviewed the JAFNPP plant-specific operating experience with components in the

auxiliary systems containing this material/environment combination and confirmed that no aging

effects that would lead to the loss of intended function have been experienced. On this basis,

the staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-8 includes AMR line items to address aluminum and

stainless steel heat exchanger coils exposed to condensation (external). The AMR line items

credit the Periodic Surveillance and Preventive Maintenance Program to manage fouling for this

component. The AMR line items cite Generic Note H, which indicates that this aging effect is

not addressed in the GALL Report for this component, material, and environment combination.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.4. The staff determined that this

program includes inspections of heat exchanger coil external surfaces using visual or other

NDE techniques to manage fouling. These inspections are performed every four years. The

staff also determined that these activities are adequate to manage fouling for aluminum and

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stainless steel heat exchanger coils exposed to condensation (external). On this basis, the staff

finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.2.2-8 includes AMR line items to address stainless steel

components in the containment purge, containment atmosphere dilution and post-accident

sampling systems exposed to air-indoor (internal). The AMR line items state that there is no

aging mechanisms or effect for this material/environment combination. The AMR line items cite

Generic Note-G, which indicates that the environment is not addressed in the GALL Report for

this component and material combination. The staff noted that stainless steels are highly

resistant to corrosion in dry atmospheres in the absence of corrosive species (which would be

reflective of indoor uncontrolled air), as cited in the Metals Handbook, Volumes 3 (p. 65) and 13

(p. 555) (Ninth Edition, American Society for Metals International, 1980 and 1987). Components

are not subject to moisture~in a dry air environment (and indoor uncontrolled air would have

limited humidity and condensation). Therefore, stainless steel in an indoor, uncontrolled air

environment exhibits no aging effect, and the component or structure will remain capable of

performing intended functions consistent with the CLB for the period of extended operation. On

this basis, the staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-8 includes AMR line items to address carbon steel and

stainless steel components in the containment purge, containment atmosphere dilution and

post-accident sampling systems exposed to vacuum. The AMR line items state that there is no

aging mechanisms or effect for this material/environment combination. The AMR line items

include a plant-specific note that states that the vacuum is between the inner and outer walls of

the liquid nitrogen tank. The AMR line items cite Generic Note G, which indicates that the

environment is not addressed in the GALL Report for this component and material combination.

Based on industry operating experience, the staff recognizes that the stainless steel/vacuum

combination is not susceptible to significant aging degradation. For the carbon steel

components, the vacuum environment essentially eliminates corrosion due to oxidation since

there is little or no oxygen present; therefore, this material/environment is not expected to be

susceptible to significant aging degradation. On this basis, the staff finds the AMR results for

these line items acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.9 Fuel Pool Cooling and Cleanup System Summary of Aging Management Evaluation -

LRA Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the

fuel pool cooling and cleanup system component groups.

The staff noted that LRA Table 3.3.2-9 includes an AMR line item to address cracking of

aluminum/boron carbide neutron absorbers exposed to treated water (external). The AMR line

item credits the Water Chemistry Control-BWR Program to manage this aging effect. The AMR

line item cites Generic Note H, which indicates that this aging effect is not addressed in the

GALL Report for this component, material, and environment combination. The staff reviewed

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the applicant's Water Chemistry Control-BWR Program and determined that this program

contains chemistry control and monitoring activities to maintain high water purity, which is

effective for managing cracking in components exposed to treated water.

In its response to the staff's inquiry on verifying the effectiveness of the Water Chemistry

Control-BWR Program for managing this aging effect, the applicant stated that the One-Time

Inspection Program will be used to verify the effectiveness of the water chemistry programs by

confirming that unacceptable cracking is not occurring. The staff determined that the applicant's

Water Chemistry Control-BWR Program and One-Time Inspection Program are adequate to

manage the cracking of aluminum/boron carbide neutron absorbers exposed to treated water

(external). On this basis, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.10 Service, Instrument, and Breathing Air Systems Summary of Aging Management

Evaluation - LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for

the service, instrument, and breathing air systems component groups, and determined that the

applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.11 Reactor Building Closed Loop Cooling Water System Summary of Aging

Management Evaluation - LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for

the reactor building closed loop cooling water system component groups, and determined that

the applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.12 Radwaste and Plant Drains Summary of Aging Management Evaluation -

LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for

the radwaste and plant drains component groups.

The staff noted that LRA Table 3.3.2-12 includes an AMR line item to address stainless steel

piping in the Radwaste and Plant Drains system exposed to air-indoor (internal). The AMR line

item states that there are no aging mechanisms or effects for this material/environment

combination. The AMR line item cites Generic Note G, which indicates that the environment is

not addressed in the GALL Report for this component and material combination. Based on

current industry research and operating experience, the staff recognizes that this

material/environment combination is not susceptible-to significant aging degradation. Stainless

steels are highly resistant to corrosion in dry atmospheres in the absence of corrosive species

(which would be reflective of indoor uncontrolled air), as cited in the Metals Handbook, Volumes

3 (p. 65) and 13 (p. 555) (Ninth Edition, American Society for Metals International, 1980 and

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1987). Components are not subject to moisture in a dry air environment (and indoor

uncontrolled air would have limited humidity and condensation). Therefore, stainless steel in an

indoor, uncontrolled air environment exhibits no aging effect, and the component or structure

will remain capable of performing intended functions consistent with the CLB for the period of

extended operation. On this basis, the staff finds the AMR results for this line item acceptable.

The staff noted that LRA Table 3.2.2-12 includes AMR line items to address fiberglass piping in

the Radwaste and Plant Drains system exposed to air-indoor (internal) and air indoor (external)

and fiberglass tanks in the Radwaste and Plant Drains system exposed to raw water (internal)

and soil (external). The AMR line items state that there are no aging mechanisms or effects for

these material/environment combinations. The AMR line items cite Generic Note F, which

indicates that the material is not addressed in the GALL Report for this component. Based on

current industry research and operating experience, the staff recognizes that this

material/environment combination is not susceptible to significant aging degradation.

In its response to the staffs inquiry regarding plant-specific operating experience with these

components, the applicant stated that its documented review of recent operating experience did

not identify any degraded conditions or failures that would indicate the presence of aging

effects for these fiberglass components. Based on current industry research and operating

experience, the staff determined that fiberglass is a highly corrosion resistant material and is

impervious to normal plant environments and is not susceptible to age degradation. On this

basis, the staff finds the AMR results for these line items acceptable

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 Security Generator Summary of Aging Management Evaluation -

LRA Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for

the security generator component groups.

The staff noted that LRA Table 3.3.2-13 includes an AMR line item to address cracking-fatigue

of stainless steel expansion joints in the security generator system exposed to air-indoor

(external). The AMR line item credits the Periodic Surveillance and Preventive Maintenance

Program to manage this aging effect. The AMR line item cites Generic Note H, which indicates

that this aging effect is not addressed in the GALL Report for this component, material, and

environment combination. The staff reviewed the applicant's Periodic Surveillance and

Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4.

The staff determined that it includes periodic inspections of components in the security

generator system using visual or other NDE techniques that will be effective for detecting

cracking. The inspections are performed every four years based on industry operating

experience and vendor recommendations. On this basis, the staff finds the AMR results for this

line item acceptable.

The staff noted that LRA Table 3.2.2-13 includes AMR line items to address fouling and loss of

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material for copper alloy heat exchanger tubes exposed to air-indoor (external). The AMR line

items credit the Periodic Surveillance and Preventive Maintenance Program to manage these

aging effects for this component. The AMR line items cite Generic Note G, which indicates that

the environment is not addressed in the GALL Report for this component and material

combination, or Generic Note H, which indicates that this aging effect is not addressed in the

GALL Report for this component, material, and environment combination. The staff reviewed

the applicant's Periodic Surveillance and Preventive Maintenance Program and determined that

it includes a yearly security generator operability test that will be effective for detecting fouling

and loss of material for the heat exchanger coils. The staff determined that these activities are

adequate to manage aging for these copper alloy heat exchanger tubes exposed to air-indoor

(external). On this basis, the staff finds the AMR results for these line items acceptable.

The staff noted that LRA Table 3.3.2-13 includes an AMR line item to address cracking-fatigue

of carbon steel piping and silencers in the security generator system exposed to exhaust gas

(internal). The AMR line item credits the Periodic Surveillance and Preventive Maintenance

Program to manage this aging effect. The AMR line item cites Generic Note H, which indicates

that this aging effect is not addressed in the GALL Report for this component, material, and

environment combination. The staff reviewed the applicant's Periodic Surveillance and

Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4.

The staff determined that it includes periodic inspections of components in the security

generator system using visual or other NDE techniques that will be effective for detecting

cracking. The inspections are performed every four years based on industry operating

experience and vendor recommendations. The staff finds these activities acceptable to manage

aging of these components. On this basis, the staff finds the AMR results for this line item

acceptable.

The staff noted that LRA Table 3.2.2-13 includes an AMR line item to address loss of material

for copper alloy tubing exposed to air-outdoor (external). The AMR line item credits the External

Surfaces Monitoring Program to manage this aging effect for these components. The AMR line

item cites Generic Note G, which indicates that the environment is not addressed in the GALL

Report for this component and material combination. The staff reviewed the applicant's External

Surfaces Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.9. The

staff determined that it includes periodic inspections of external surfaces for components in the

security generator systems that will be effective for detecting loss of material for these

components. The staff determined that these activities are adequate to manage aging for these

copper alloy tubing components exposed to air-outdoor (external). On this basis, the staff finds

the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.14 Standby Liquid Control System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-5

The staff reviewed LRA Table 3.3.2-14-5, which summarizes the results of AMR evaluations for

the SLC system component groups, and determined that the applicant did not include any AMR

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results with Generic Notes F through J involving material, environment, AERMs, and AMP

combinations that are not evaluated in the GALL Report.

3.3.2.3.15 Reactor Water Cleanup System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-6

The staff reviewed LRA Table 3.3.2-14-6, which summarizes the results of AMR evaluations for

the reactor water cleanup system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.16 Reactor Building Closed Loop Cooling Water System, Nonsafety-Related

Components Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-9

The staff reviewed LRA Table 3.3.2-14-9, which summarizes the results of AMR evaluations for

the reactor building closed loop cooling water system component groups, and determined that

the applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.17 Process Radiation Monitors, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-11

The staff reviewed LRA Table 3.3.2-14-11, which summarizes the results of AMR evaluations

for the process radiation monitors component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.18 Fuel Pool Cooling and Cleanup System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-12

The staff reviewed LRA Table 3.3.2-14-12, which summarizes the results of AMR evaluations

for the fuel pool cooling and cleanup system component groups, and determined that the

applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.19 Radwaste System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-13

The staff reviewed LRA Table 3.3.2-14-13, which summarizes the results of AMR evaluations

for the radwaste system component groups, and determined that the applicant did not include

any AMR results with Generic Notes F through J involving material, environment, AERMs, and

AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.20 Containment Purge/CAD/PASS System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-15

The staff reviewed LRA Table 3.3.2-14-15, which summarizes the results of AMR evaluations

for the containment purge/CAD/PASS system component groups, and determined that the

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applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.21 Decay Heat Removal System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-18

The staff reviewed LRA Table 3.3.2-14-18, which summarizes the results of AMR evaluations

for the decay heat removal system component groups, and determined that the applicant did

not include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.22 Turbine Building Closed Loop Cooling System, Nonsafety-Related Components

Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-23

The staff reviewed LRA Table 3.3.2-14-23, which summarizes the results of AMR evaluations

for the turbine building closed loop cooling system component groups.

The staff noted that LRA Table 3.3.2-14-23 includes AMR line items to address plastic tanks in

the TBCLC system exposed to air-indoor (external) and treated water (internal). The AMR line

items state that there are no aging mechanisms or effects for these material/environment

combinations. The AMR line items cite Generic Note F, which indicates that the material is not

addressed in the GALL Report for this component. Based on current industry research and

operating experience, the staff recognizes that this material/environment combination is not

susceptible to significant aging degradation. The staff noted that air-indoor (external) and

treated water (internal) on polyvinyl chloride (PVC)/ chlorinated PVC will not cause aging of

concern during the period of extended operation because there are no stressors present

according to industry standards. Therefore, the staff concludes that there are no applicable

aging effects requiring management for plastic tanks in the TBCLC system exposed to

air-indoor (external) and treated water (internal).

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.3.2.3.23 Vacuum Priming and Air Removal System, Nonsafety-Related Components

Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-24

The staff reviewed LRA Table 3.3.2-14-24, which summarizes the results of AMR evaluations

for the vacuum priming and air removal system component groups, and determined that the

applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

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3.3.2.3.24 Service/Instrument/Breathing Air System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-25

The staff reviewed LRA Table 3.3.2-14-25, which summarizes the results of AMR evaluations

for the service/instrument/breathing air system component groups, and determined that the

applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.25 Turbine Lube Oil System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation -,LRA Table 3.3.2-14-26

-The staff reviewed LRA Table 3.3.2-14-26, which summarizes the results of AMR evaluations

for the turbine lube oil system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.26 Secondary Plant Drains, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-27

The staff reviewed LRA Table 3.3.2-14-27, which summarizes the results of AMR evaluations

for the secondary plant drains component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.27 Raw Water Treatment System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-28

The staff reviewed LRA Table 3.3.2-14-28, which summarizes the results of AMR evaluations

for the raw water treatment system component groups, and determined that the applicant did

not include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.28 Contaminated Equipment Drains, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-29

The staff reviewed LRA Table 3.3.2-14-29, which summarizes the results of AMR evaluations

for the contaminated equipment drains component groups, and determined that the applicant

did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.29 Service Water System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-30

The staff reviewed LRA Table 3.3.2714-30, which summarizes the results of AMR evaluations

for the service water system component groups.

The staff noted that LRA Table 3.3.2-14-30 includes AMR line items to address plastic tanks in

the Service Water system exposed to air-indoor (external) and raw water (internal). The AMR

line items state that there are no aging mechanisms or effects for these material/environment

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combinations. The AMR line items cite Generic Note F, which indicates that the material is not

addressed in the GALL Report for this component. Based on current industry research and

operating experience, the staff recognizes that this material and environment combination is not

susceptible to significant aging degradation. The staff noted that air-indoor (external) and raw

water (internal) on PVC/chlorinated PVC will not cause aging of concern during the period of

extended operation because there are no stressors present according to industry standards.

Therefore, the staff concludes that there are no applicable aging effects requiring management

for plastic tanks in the Service Water system exposed to air-indoor (external) and raw water

(internal). On this basis, the staff finds the AMR results for these line items acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will b&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).

3.3.2.3.30 Auxiliary Gas Treatment System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-31

The staff reviewed LRA Table 3.3.2-14-31, which summarizes the results of AMR evaluations

for the auxiliary gas treatment system component groups.

The staff noted that LRA Table 3.3.2-14-31 includes AMR line items to address stainless steel

duct in the Auxiliary Gas Treatment system exposed to air-indoor (internal). The AMR line items

state that there are no aging mechanisms or effects for this material and environment

combination. The AMR line items cite Generic Note G, which indicates that the environment is

not addressed in the GALL Report for this component and material combination. Based on

current industry research and operating experience, the staff recognizes that this

material/environment combination is not susceptible to significant aging degradation. Stainless

steels are highly resistant to corrosion in dry atmospheres in the absence of corrosive species

(which would be reflective of indoor uncontrolled air), as cited in the Metals Handbook, Volumes

3 (p. 65) and 13 (p. 555) (Ninth Edition, American Society for Metals International, 1980 and

1987). Components are not subject to moisture in a dry air environment (and indoor

uncontrolled air would have limited humidity and condensation). Therefore, stainless steel in an

indoor, uncontrolled air environment exhibits no aging effect, and the component or structure

will remain capable of performing intended functions consistent with the CLB for the period of

extended operation. On this basis, the staff finds the AMR results for these line items

acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.3.2.3.31 Reactor Building Ventilation System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-32

The staff reviewed LRA Table 3.3.2-14-32, which summarizes the results of AMR evaluations

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for the reactor building ventilation system component groups, and determined that the applicant

did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.32 Turbine Building Ventilation System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-33

The staff reviewed LRA Table 3.3.2-14-33, which summarizes the results of AMR evaluations

for the turbine building ventilation system component groups, and determined that the applicant

did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.33 Drywell Ventilation and Cooling System, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-34

The staff reviewed LRA Table 3.3.2-14-34, which summarizes the results of AMR evaluations

for the drywell ventilation and cooling system component groups, and determined that the

applicant did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.34 Administration Building Ventilation and Cooling System, Nonsafety-Related

Components Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-35

The staff reviewed LRA Table 3.3.2-14-35, which summarizes the results of AMR evaluations

for the administration building ventilation and cooling system component groups, and

determined that the applicant did not include any AMR results with Generic Notes F through J

involving material, environment, AERMs, and AMP combinations that are not evaluated in the

GALL Report.

3.3.2.3.35 Screenwell/Water Treatment Ventilation and Cooling System, Nonsafety-Related

Components Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-36

The staff reviewed LRA Table 3.3.2-14-36, which summarizes the results of AMR evaluations

for the screenwell/water treatment ventilation and cooling system component groups, and

determined that the applicant did not include any AMR results with Generic Notes F through J

involving material, environment, AERMs, and AMP combinations that are not evaluated in the

GALL Report.

3.3.2.3.36 Plumbing, Sanitary, and Lab, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-37

The staff reviewed LRA Table 3.3.2-14-37, which summarizes the results of AMR evaluations

for the plumbing, sanitary, and lab component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

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3.3.2.3.37 Fire Protection System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-38

The staff reviewed LRA Table 3.3.2-14-38, which summarizes the results of AMR evaluations

for the fire protection system component groups, and determined that the applicant did not

include any AMR results with Generic Notes F through J involving material, environment,

AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.38 City Water System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-39

The staff reviewed LRA Table 3.3.2-14-39, which summarizes the results of AMR evaluations

for the city water system component groups, and determined that the applicant did not include

any AMR results with Generic Notes F through J involving material, environment, AERMs, and

AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.39 Auxiliary Boiler and Accessories, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-40

The staff reviewed LRA Table 3.3.2-14-40, which summarizes the results of AMR evaluations

for the auxiliary boiler and accessories component groups, and determined that the applicant

did not include any AMR results with Generic Notes F through J involving material,

environment, AERMs, and AMP combinations that are not evaluated in the GALL Report.

3.3.2.3.40 Emergency Diesel Generator, Nonsafety-Related Components Affecting

Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-41

The staff reviewed LRA Table 3.3.2-14-41, which summarizes the results of AMR evaluations

for the emergency diesel generator component groups.

The staff noted that LRA Table 3.2.2-14-41 includes AMR line items to address

nonsafety-related carbon steel compressor housings, piping, and valve bodies in the EDG

system that could affect safety-related systems exposed to air-untreated (internal). The AMR

line items credit the One-Time Inspection Program to manage cracking-fatigue for these

components. The AMR line items cite Generic Note H, which indicates that this aging effect is

not addressed in the GALL Report for this component, material, and environment combination.

In its response to the staffs inquiry to explain how the one-time inspection will manage this

aging effect throughout the period of extended operation, the applicant stated that the

components in these AMR line items are included in-scope only for structural support of the

safety-related components in the EDG air start subsystem. This aging effect was conservatively

identified due to the potential for high temperature thermal cycling of the discharge piping. The

one-time inspection will confirm through visual or NDE techniques that cracking is not occurring

or is so insignificant that an ongoing aging management program is not warranted. If significant

cracking is detected, corrective actions will be taken in accordance with the site corrective

action program. The staff reviewed the applicant's One-Time Inspection Program and its

evaluation is documented in SER Section 3.0.3.1.6. The staff determined that it includes

inspections using visual or other NDE techniques that are effective for detecting cracking. Since

these components are included in-scope only for structural support of the safety-related

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components in the EDG air start subsystem, and this aging effect was identified due to the

potential for high temperature thermal cycling of the discharge piping, the staff finds that a

one-time inspection to confirm that significant aging degradation is not occurring is acceptable.

On this basis, the staff finds the AMR results for these line items acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.3.2.3.41 Sample System, Nonsafety-Related Components Affecting Safety-Related Systems

Summary of Aging Management Evaluation - LRA Table 3.3.2-14-43

The staff reviewed LRA Table 3.3.2-14-43, which summarizes the results of AMR evaluations

for the sample system component groups, and determined that the applicant did not include any

AMR results with Generic Notes F through J involving material, environment, AERMs, and AMP

combinations that are not evaluated in the GALL Report.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended 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 system components within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4 Aging Management of Steam and Power Conversion Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

steam and power conversion system (S&PC) components and component groups of the

following:

* Condensate storage system

* MS, turbine generator auxiliaries, and main condenser

• Miscellaneous systems within the S&PC system in-scope for 10 CFR 54.4(a)(2) (These

S&PC subsystems are included in LRA Section 3.3, "Auxiliary Systems," but are

evaluated in this section.)

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3.4.1 Summary of Technical Information in the Application

In LRA Section 3.4, the applicant provided AMR results for the S&PC system components and

component groups. In LRA Table 3.4.1, "Summary of Aging Management Programs for the

S&PC System Evaluated in Chapter VIII of NUREG-1801 ," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the S&PC system

components and component groups.

In LRA Tables 3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, 3.3.2-14-21, 3.3.2-14-22,

3.3.2-14-42, and 3.3.2-14-44, the applicant provided results for component types associated

with the following S&PC subsystems in-scope for 10 CFR 54.4(a)(2).

* MS system, nonsafety-related components affecting safety-related systems

* extraction steam system, nonsafety-related components affecting safety-related

systems

• condensate system, nonsafety-related components affecting safety-related systems

* feedwater system, nonsafety-related components affecting safety-related systems

* feedwater heater vents and drains system, nonsafety-related components affecting

safety-related systems

" circulating water system, nonsafety-related components affecting safety-related systems

• main turbine generator, nonsafety-related components affecting safety-related systems

* steam seal system, nonsafety-related components affecting safety-related systems

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of 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 S&PC system components, that are

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 confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.4.2.1.

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In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.4.2.2. The staff's

audit evaluations are documented in SER Section 3.4.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

effects listed were appropriate for the combination of materials and environments specified. The

staff's audit evaluations are documented in SER Section 3.4.2.3. The staff's evaluation of the

technical review.is also documented in SER Section 3.4.2.3.

Finally, the staff reviewed tlhe AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the S&PC system components.

Table 3.4-1 includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.4, that are addressed in the GALL

Report.

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

the GALL Report

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

ItemNo.)

Steel piping, piping Cumulative fatigue TLAA, evaluated in TLAA Consistent with

components, and damage accordance with GALL Report, which

piping elements 10 CFR 54.21 (c) recommends further

exposed to steam evaluation (See

or treated water SER

(3.4.1-1) Section 3.4.2.2.1)

Steel piping, piping Loss of material Water Chemistry Water Chemistry Consistent with

components, and due to general, and One-Time Control - BWR GALL Report, which

piping elements pitting and crevice Inspection Program (B.1.29.2) recommends further

exposed to steam corrosion and One-Time evaluation (See

(3.4.1-2) Inspection Program SER

(B.1.21) Section 3.4.2.2.2)

Steel heat Loss of material Water Chemistry None Not applicable to

exchanger due to general, and One-Time BWRs

components pitting and crevice Inspection

exposed to treated corrosion

water

(3.4.1-3)

Steel piping, piping Loss of material Water Chemistry Water Chemistry Consistent with

components, and due to general, and One-Time Control - BWR GALL Report, which

piping elements pitting and crevice Inspection Program (B.1.29.2) recommends further

exposed to treated corrosion and One-Time evaluation (See

water Inspection Program SER

(3.4.1-4) (B.1.21) Section 3.4.2.2.2)

3-335
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel heat Loss of material Water Chemistry Water Chemistry Consistent with

exchanger due to general, and One-Time Control - BWR GALL Report, which

components pitting, crevice, and Inspection Program (B.1.29.2) recommends further

exposed to treated galvanic corrosion and One-Time evaluation (See

water Inspection Program SER

(3.4.1-5) (B.1.21) Section 3.4.2.2.9)

Steel and stainless Loss of material Water Chemistry Water Chemistry Consistent with

steel tanks exposed due to general and One-Time Control - BWR GALL Report, which

to treated water (steel only) pitting Inspection Program (B.1.29.2) recommends further

(3.4.1-6). and crevice and One-Time evaluation (See j corrosion Inspection Program SER

(B.1.21) Section 3.4.2.2.7

and 3.4.2.2.2 for

steel tanks)

Steel piping, piping Loss of material Lubricating Oil Oil analysis Consistent with

components, and due to general, Analysis'and Program (B.1.20) GALL Report, which

piping elements pitting and crevice One-Time and One-Time recommends further

exposed to corrosion Inspection Inspection Program evaluation (See

lubricating oil (B.1.21) SER

(3.4.1-7) Section 3.4.2.2.2)

Steel piping, piping Loss of material Plant specific Periodic Consistent with

components, and due to general, Surveillance and GALL Report, which

piping elements pitting, crevice, and Preventive recommends further

exposed to raw microbiologically- Maintenance evaluation (See

water influenced Program (B.1.22) SER

(3.4.1-8) corrosion, and Section 3.4.2.2.3)

fouling

Stainless steel and Reduction of heat Water Chemistry Water Chemistry Consistent with

copper alloy heat transfer due to. and One-Time Control - BWR GALL Report, which

exchanger tubes fouling Inspection Program (B.1.29.2) recommends further

exposed to treated and One-Time evaluation (See

water Inspection Program SER

(3.4,1-9) (B.1.21) Section 3.4.2.2.4)

Steel, stainless Reduction of heat Lubricating Oil None Not applicable (See

steel, and copper transfer due to Analysis and SER

alloy heat fouling One-Time Section 3.4.2.2.4)

exchanger tubes Inspection

exposed to

lubricating oil

(3.4.1-10)

Buried steel piping, Loss of material Buried Piping and None Not applicable (See

piping components, due to general, Tanks Surveillance SER

piping elements, pitting, crevice, and or Buried Piping Section 3.4.2.2.5)

and tanks (with or microbiologically- and Tanks

without coating or influenced corrosion Inspection

wrapping) exposed

to soil

(3.4.1-11)

3-336
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel heat Loss of material Lubricating Oil Oil analysis Consistent with

exchanger due to general, Analysis and Program (B.1.20) GALL Report, which

components pitting, crevice, and ne-Time Inspection recommends further

exposed to microbiologically- evaluation (See

lubricating oil influenced corrosion SER

(3.4.1-12) Section 3.4.2.2.5)

Stainless steel Cracking due to Water Chemistry Water Chemistry Consistent with

piping, piping stress corrosion and One-Time Control - BWR GALL Report, which

components, piping cracking Inspection Program (B.1.29.2) recommends further

elements exposed and One-Time: evalutation (See

to steam -Inspection Program SER,

(3.4.1-13) (B.1.21) Section 3.4.2.2.6)

Stainless steel Cracking due to Water Chemistry Water Chemistry Consistent with

piping, piping stress corrosion and One-Time Control - BWR GALL Report, which

components, piping cracking Inspection Program(B.1.29.2) recommends further

elements, tanks, and One-Time evaluation (See

and heat exchanger Inspection Program SER

components (B.1.21) Section 3.4.2.2.6)

exposed to treated

water > 60 0C

(> 1400F)

(3.4.1-14)

Aluminum and Loss of material Water Chemistry None Not applicable (See

copper alloy piping, due to pitting and and One-Time SER

piping components, crevice corrosion Inspection Section 3.4.2.2.7)

and piping elements

exposed to treated

water

(3.4.1-15)

Stainless steel Loss of material Water Chemistry Water Chemistry Consistent with

piping, piping due to pitting and and One-Time Control - BWR GALL Report, which

components, and crevice corrosion Inspection Program (B.1.29.2) recommends further

piping elements; and One-Time evaluation (See

tanks, and heat Inspection Program SER

exchanger (B.1.21) Section 3.4.2.2.7)

components

exposed to treated

water

(3.4.1-16)

Stainless steel Loss of material Plant specific Buried Piping and Consistent with

piping, piping due to pitting and Tanks Inspection GALL Report, which

components, and crevice corrosion Program (B.1.1) recommends further

piping elements evaluation (See

exposed to soil SER

(3.4.1-17) Section 3.4.2.2.7)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Copper alloy piping, Loss of material Lubricating Oil Oil analysis Consistent with

piping components, due to pitting and Analysis and Program (B.1.20) GALL Report, which

and piping elements crevice corrosion One-Time and One-Time recommends further

exposed to Inspection Inspection Program evaluation (See

lubricating oil (B.1.21) SER

(3.4.1-18) Section 3.4.2.2.7)

Stainless steel Loss of material Lubricating Oil Oil analysis Consistent with

piping, piping due to pitting, Analysis and Program (B.1.20) GALL Report, which

components, piping crevice, and One-Time and One-Time recommends further

elements, and heat microbiologically- Inspection Inspection Program evaluation (See

exchanger . influenced!corrosion (B.1.21) SER

components Section 3.4.2.2.8)

exposed to

lubricating oil

(3.4.1-19)

Steel tanks exposed Loss of material/ Aboveground Steel None Not applicable (See

to air - outdoor general, pitting, and Tanks SER

(external) crevice corrosion Section 3.4.2.1.2)

(3.4.1-20)

High-strength steel Cracking due to Bolting Integrity None Not applicable (See

closure bolting cyclic loading, SER

exposed to air with stress corrosion Section 3.4.2.1.2)

steam or water cracking

leakage

(3.4.1-21)

Steel bolting and Loss of material Bolting Integrity Bolting Integrity Consistent with

closure bolting due to general, Program (B.1.30) GALL Report,, which

exposed to air with pitting and crevice recommends no

steam or water corrosion; loss of further evaluation

leakage, air - preload due to (See SER

outdoor (external), thermal effects, Section 3.4.2.1)

or air - indoor gasket creep, and

uncontrolled self-loosening

(external);

(3.4.1-22)

Stainless steel Cracking due to Closed-Cycle None Not applicable (See

piping, piping stress corrosion Cooling Water SER

components, and cracking System Section 3.4.2.1.2)

piping elements

exposed to

closed-cycle cooling

water > 60'C

(> 140 0 F)

(3.4.1-23)

Steel heat Loss of material Closed-Cycle None Not applicable (See

exchanger due to general, Cooling Water SER

components pitting, crevice, and System Section 3.4.2.1.2)

exposed to closed galvanic corrosion

cycle cooling water

(3.4.1-24)

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Component Group Aging Effectl AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Stainless steel Loss of material Closed-Cycle Water Chemistry Consistent with

piping, piping due to pitting and Cooling Water Control - Auxiliary GALL Report, which

components, piping crevice corrosion System Systems Program recommends no

elements, and heat (B.1.29.1) further evaluation

exchanger (See SER

components Section 3.4.2.1)

exposed to closed

cycle cooling water

(3.4.1-25)

Copper alloy piping, Loss of material Closed-Cycle Water Chemistry Consistent with

piping components, due to pitting,_ . Cooling Water s Control - Auxiliary GALL Report, which

and piping elements crevice, and System Systems Program recommends no

exposed to closed galvanic corrosion (B.1.29.1) further evaluation

cycle cooling water (See SER

(3.4.1-26) Section 3.4.2.1)

Steel, stainless Reduction of heat Closed-Cycle None Not applicable (See

steel, and copper transfer due to Cooling Water SER

alloy heat fouling System Section 3.4.2.1.2)

exchanger tubes

exposed to closed

cycle cooling water

(3.4.1-27)

Steel external Loss of material External Surfaces External Surfaces Consistent with

surfaces exposed to due to general Monitoring Monitoring Program GALL Report, which

air - indoor corrosion (B.1.11) recommends no

uncontrolled further evaluation

(external), (See SER

condensation Section 3.4.2.1)

(external), or air

outdoor (external)

(3.4.1-28)

Steel piping, piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with

components, and flow-accelerated Corrosion Corrosion Program GALL Report, which

piping elements corrosion (B.1.14) recommends no

exposed to steam further evaluation

or treated water (See SER

(3.4.1-29) Section 3.4.2.1)

Steel piping, piping Loss of material Inspection of None Not applicable (See

components, and due to general, Internal Surfaces in SER

piping elements pitting, and crevice Miscellaneous Section 3.4.2.1.2)

exposed to air corrosion Piping and Ducting

outdoor (internal) or Components

condensation

(internal)

(3:4.1-30)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel heat Loss of material Open-Cycle Cooling None Not applicable (See

exchanger due to general, Water System SER

components pitting, crevice, Section 3.4.2.1.2)

exposed to raw galvanic, and

water microbiologically-

(3.4.1-31) influenced

corrosion, and

fouling

Stainless steel and Loss of material Open-Cycle Cooling Periodic Consistent with

copper alloy piping, due to pitting, Water System Surveillance and GALL Report, which

piping components, crevice, and Preventive recommends no

and piping elements microbiologically- Maintenance further evaluation

exposed to raw influenced corrosion Program (B.1.22) (See SER

water Section 3.4.2.1.1)

(3.4.1-32)

Stainless steel heat Loss of material Open-Cycle Cooling None Not applicable (See

exchanger due to pitting, Water System SER

components crevice, and Section 3.4.2.1.2)

exposed to raw microbiologicallywater influenced

(3.4.1-33) corrosion, and

fouling

Steel, stainless Reduction of heat Open-Cycle Cooling None Not applicable (See

steel, and copper transfer due to Water System SER

alloy heat fouling Section 3.4.2.1.2)

exchanger tubes

exposed to raw

water

(3.4.1-34)

Copper alloy Loss of material Selective Leaching None Not applicable (See

> 15% Zn piping, due to selective of Materials SER

piping components, leaching Section 3.4.2.1.2)

and piping elements

exposed to closed

cycle cooling water,

raw water, or

treated water

(3.4.1-35)

Gray cast iron Loss of material Selective Leaching None Not applicable (See

piping, piping due to selective of Materials SER

components, and leaching Section 3.4.2.1.2)

piping elements

exposed to soil,

treated water, or

raw water

(3.4.1-36)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel, stainless Loss of material Water Chemistry Water Chemistry Consistent with

steel, and due to pitting and Control - BWR GALL Report, which

nickel-based alloy crevice corrosion Program (B.1.29.2) recommends no

piping, piping further evaluation

components, and (See SER

piping elements Section 3.4.2.1)

exposed to steam

(3.4.1-37)

Steel bolting and Loss of material, Boric Acid None Not applicable to

external surfaces due to boric acid Corrosion BWRs

exposed to air with corrosion

borated water

leakage

(3.4.1-38)

Stainless steel Cracking due to Water Chemistry None Not applicable to

piping, piping stress corrosion BWRs

components, and cracking

piping elements

exposed to steam

(3.4.1-39)

Glass piping None None None Consistent with

elements exposed GALL Report

to air, lubricating oil,

raw water, and

treated water

(3.4.1-40)

Stainless steel, None None None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping components,

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.4.1-41)

Steel piping, piping None None None Not applicable (See

components, and SER

piping elements Section 3.4.2.1.2)

exposed to air -

indoor controlled

(external)

(3.4.1-42)

Steel and stainless None None None Consistent with

steel piping, piping GALL Report

components, and

piping elements in

concrete

(3.4.1-43)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel, stainless None None None Not applicable (See

steel, aluminum, SER

and copper alloy Section 3.4.2.1.2)

piping, piping

components, and

piping elements

exposed to gas

(3.4.1-44)

The staff's review of the S&PC system component groups followed one of several approaches.

One approach, documented in SER Section 3.4.2.1, discusses the staff's review of the AMR

results for components that the applicant indicated are consistent with the GALL Report and do

not require further evaluation. Another approach, documented in SER Section 3.4.2.2,

discusses the staff's review of the AMR results for components that the applicant indicated are

consistent with the GALL Report and for which further evaluation is recommended. A third

approach, documented in SER Section 3.4.2.3, discusses the staffs review of the AMR results

for components that the applicant indicated are not consistent with, or not addressed in, the

GALL Report. The staff's review of AMPs that are credited to manage or monitor aging effects

of the S&PC system components is documented in SER Section 3.0.3.

3.4.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the S&PC system components:

" Bolting Integrity Program

" Buried Piping and Tanks Inspection Program

" External Surfaces Monitoring Program

* One-Time Inspection Program

" Water Chemistry Control - BWR Program

In LRA Tables 3.4.2-1, 3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, 3.3.2-14-21,

3.3.2-14-22, 3.3.2-14-42, and 3.3.2-14-44 the applicant provided a summary of AMRs for the

S&PC system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL.Report does not

recommend further evaluation, the staff performed an audit and review to determine whether

the plant-specific components contained in these GALL Report component groups were

bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

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Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, aging effect, and aging management program. In addition, the AMP is

consistent with the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report and the validity of the AMR for the site-specific

conditions.

Note B indicates that the.AMR line item is consistent with the GALL Report for component,

material, environment, aging effect, and aging management program. In addition, the AMP

takes some exceptions to the AMP identified in the GALL Report. The staff audited these line

items to verify consistency with the GALL Report. The staff verified that the identified

exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff also

determined whether the AMP identified by the applicant is consistent with the AMP identified in

the GALL Report and whether the AMR was valid -for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the AMP identified by the GALL Report. This note indicates that the

applicant was unable to find a listing of some system components in the GALL Report;

however, the applicant identified a different component in the GALL Report that has the same

material, environment, aging effect, and AMP as the component that was under review. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the AMR line. item of the different component was applicable to the

component under review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these

line items to verify consistency with the GALL Report. The staff verified whether the AMR line

item of the different component was applicable to the component under review. The staff

verified whether the identified exceptions to the GALL AMPs had been reviewed and accepted

by the staff. The staff also determined whether the AMP identified by the applicant was

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the

site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified in the GALL

Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided 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 is discussed below.

3.4.2.1.1 Loss of Material Due to General, Pitting, and Crevice Corrosion and

Microbiologically-influenced Corrosion

In LRA Table 3.3.2-14-22, circulating water system, which cites Table 3.4. 1, item 3.4.1-32, the

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applicant proposed to manage loss of material of stainless steel and copper alloy piping, piping

components, and piping elements exposed to raw water using the Periodic Surveillance and

Preventive Maintenance Program. However, the AMP recommended by the GALL Report for

this AERM is GALL AMP XI.M20, "Open-Cycle Cooling Water System Program." The applicant

included a reference to Note E to the associated Table 2 line items, indicating a different AMP

is credited. In the discussion column in Table 3.4.1, Items 3.4.1-32, the applicant stated that the

Periodic Surveillance and Preventive Maintenance Program manages loss of material for

copper alloy components exposed to raw water through periodic visual inspections. The

applicant also stated that there are no stainless steel components exposed to raw water with an

intended function of pressure boundary in the S&PC system.

The staff reviewed the AMR result lines referring to Note E and determined that the component

type, :material, environment, and aging effect are consistent with those of the corresponding line

of the GALL Report. The staff reviewed the applicant's Periodic Surveillance and Preventive

Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff

found the use of the Periodic Surveillance and Preventive Maintenance Program to manage

loss of material of copper alloy piping, piping components, and piping elements exposed to raw

water to be acceptable because the Periodic Surveillance and Preventive Maintenance Program

detects leakage and manages material degradation through periodic visual inspections. The

staff concludes that this AMP addressed the AEM as recommended by the GALL Report.

On the basis of its review, the staff finds that the applicant appropriately addressed the loss of

material due to general, pitting and crevice corrosion and MIC for copper alloy piping, piping

components, and piping elements exposed to raw water.

3.4.2.1.2 AMR Results Identified as Not Applicable

In LRA Table 3.4.1, line items 20, 21, 23, 24, 27, 30, 31, 33, 34, 35, 36, 42, and 44 are

identified as "Not Applicable" since the component/material/ environment combination does not

exist at JAFNPP. For each of these line items, the staff reviewed the LRA and the applicant's

supporting documents, and confirmed the applicant's claim that the

component/material/environment combination does not exist at JAFNPP. On the basis that

JAFNPP does not have the component/material/ environment combination for these Table 1

line items, the staff finds that these AMRs are not applicable to JAFNPP.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing the associated aging effects. On the basis of its review,

the staff concludes that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are indeed consistent with the AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.4.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for

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the S&PC system components. The applicant provided information concerning how it will

manage the following aging effects:

" cumulative fatigue damage

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion, and fouling

* reduction of heat transfer due to fouling

• loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion

* cracking due to stress corrosion cracking

* loss of material due to pitting and crevice corrosion

* loss of material due to pitting, crevice, and microbiologically-influenced corrosion

* loss of material due to general, pitting, crevice, and galvanic corrosion

* QA for aging management of nonsafety-related components

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The

staff's evaluation of the aging effects is discussed in the following sections.

3.4.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1).

The staff reviewed the AMR line items in the Type 2 AMR tables for the steam and power

conversion system in which fatigue-induced damage (to which the AMR line items refer as

"fatigue - cracking'") was shown as an AERM and in which the "TLAA - Metal Fatigue" was

credited as the basis for management of the aging effect. This SER will refer to these AMR line

items in the Type 2 AMR tables for the steam and power conversion systems as "AMRs on

Non-Class 1 Fatigue" and to the relevant TLAA as the "TLAA on Metal Fatigue of Non-Class 1

Components."

SER Section 4.3.2.2 documents the staff's review of the applicant's evaluation of this TLAA for

Non-Class 1 components, including non-class 1 portions of the S&PC system.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.2 against the SRP-LR Section 3.4.2.2.2 criteria.

(1) In LRA Section 3.4.2.2.2, the applicant stated that the loss of material due to general,

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pitting, and crevice corrosion for carbon steel piping, piping components, and tanks

exposed to treated water and for carbon steel piping and components exposed to steam

is an aging effect requiring management in the S&PC and other systems at JAFNPP

and is managed by the Water Chemistry Control - BWR Program. The effectiveness of

the Water Chemistry Control - BWR Program will be confirmed by the One-Time

Inspection Program through an inspection of a representative sample of components

crediting this program, including susceptible locations such as areas of stagnant flow.

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion could occur for steel piping, piping components, piping elements, tanks, and

heat exchanger components exposed to treated water and for steel piping, piping

components, and piping elements exposed to steam. The existing aging management

program relies on monitoring and control of water chemistry to manage the effects of

loss of material due to general, pitting, and crevice corrosion. However, control of water

chemistry does not preclude loss of material due to general, pitting, and crevice

corrosion at locations of stagnant flow conditions. Therefore, the effectiveness of the

Water Chemistry Control Program should be verified to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to verify the

effectiveness of the Water Chemistry Control Program. A one-time inspection of select

components and susceptible locations is an acceptable method to ensure that corrosion

is not occurring and that the component's intended function will be maintained during

the period of extended operation.

In the discussion column of Table 3.4.1, items 3.4.1-2, 3.4.1-4, and 3.4.1-6, the

applicant stated that the One-Time Inspection Program will be used to verify the

effectiveness of the Water Chemistry Control Program. However, for those line items in

Tables 3.4.2-1, 3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, 3.3.2-14-21,

3.3.2-14-42, and 3.3.2-14-44, where these Table 3.4.1 line items are referenced in the

S&PC System, only the Water Chemistry Control - BWR Program is credited under

Aging Management Programs. The staff noted that the Table 2 AMR line items, in the

LRA, that reference this Table 1 line item cite Note 401, indicating that the effectiveness

of the Water Chemistry Control - BWR Program will be verified by the One-Time

inspection Program. The staff determined that the use of One-Time Inspection Program

to verify the effectiveness of the water chemistry control program is consistent with the

recommendations in GALL Report, and is acceptable.

The staff reviewed the applicant's Water Chemistry Control - BWR Program and its

evaluation is documented in SER Section 3.0.3.1.10. The staff verified that this AMP

included activities that monitor and control water chemistry to manage the effects of loss

of material due to general, pitting, and crevice corrosion consistent with GALL

AMP XI.M2. In addition, the staff verified that the One-Time Inspection Program

included inspection activities to verify the effectiveness of Water Chemistry Control

Program to manage loss of material due to general, pitting, and crevice corrosion at

locations of stagnant flow conditions. On the basis that One-Time Inspection will be

performed on the components, the staff determined that the Water Chemistry Control -

BWR Program is appropriate for the AEMs identified and provides assurance that the

AEMs will be effectively managed through the period of extended operation.

The staff finds that, based on the programs identified above, the applicant has met the

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criteria of SRP-LR Section 3.5.2.2.2.2, item 1, for further evaluation.

(2) In LRA Section 3.4.2.2.2, the applicant stated that loss of material due to general,

pitting, and crevice corrosion in steel piping and components exposed to lubricating oil is

managed by the Oil Analysis Program, which includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. During the past five years, many visual

inspections of components containing lubricating oil have been performed during

corrective and preventive maintenance activities. The visual inspections of these

components would identify degraded conditions such as fouling, corrosion or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one-time inspection to provide. confirmation of the

effectiveness of the Oil Analysis Program.

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion could occur for steel piping, piping components, and piping elements exposed

to lubricating oil. The existing AMP relies on the periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil contaminant control should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage corrosion to verify the effectiveness of the Lubricating Oil Analysis

Program. A One-Time Inspection of selected components at susceptible locations is an

acceptable method to ensure that corrosion is not occurring and that the component's

intended function will be maintained during the period of extended operation.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is

documented in SER Section 3.0.3.2.14. The staff determined that this program includes

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits. The staff finds that these activities are consistent with the

recommendations in GALL Report, and are adequate to manage loss of material due to

general, pitting, and crevice corrosion for steel piping, piping components, and piping

elements exposed to lubricating oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection Program AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection

Program AMP. In its letter dated February 1, 2007 (Amendment 5 to the LRA), the

applicant revised the LRA Section 3.4.2.2.2, item 2, to state that "One time Inspection

Program activities will be utilized to confirm the effectiveness of the Oil Analysis

Program." The staff finds that the use of the one-time inspection to verify the

effectiveness of the oil analysis program is consistent with the recommendations in

GALL Report, and is acceptable.

The staff finds that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.2,

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item 2, for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.4.2.2.2. For those line items that apply to LRA Section 3.4.2.2.2,

the staff determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion (MIC), and Fouling

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.

In LRA Section 3.4.2.2.3, the applicant stated that loss of material due to general, pitting,

crevice, and MIC, and fouling in steel piping and components in the S&PC system exposed to

raw water is managed by the Periodic Surveillance and Preventive Maintenance Program. The

program includes visual inspections and other NDE techniques to manage loss of material of

the components. These inspections will manage the aging effect of loss of material such that

the intended function of the components will not be affected.

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, crevice, and MIC,

and fouling could occur in steel piping, piping components, and piping elements exposed to raw

water. The GALL Report recommends further evaluation of a plant-specific Aging Management

Program to ensure that these aging effects are adequately managed. Acceptance criteria are

described in Branch Technical Position RLSB-1 (Appendix A.1 of SRP-LR)

The staff reviewed the specific components in the circulating water system (CWS) that are

represented by four line items in Table 3.3.2-14-22, which reference Table 3.4.1, item 3.4.1-8

and credit the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed

the Periodic Surveillance and Preventive Maintenance Program and its evaluation is

documented in SER. Section 3.0.3.3.4. The staff found that the applicant's Periodic

Surveillance and Preventive Maintenance Program includes using visual or other NDE

techniques to inspect a representative sample of CWS to manage internal loss of material. The

staff concludes that this AMP will assure detection of leakage before the loss of its intended

function and that this AMP will adequately manage loss of material due to general, pitting,

crevice, and MIC and fouling in steel piping, piping components, and piping elements exposed

to raw water.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.4.2.2.3 for further evaluation. For those line items that apply to

LRA Section 3.4.2.2.3, the staff determines that the LRA is consistent with the GALL Report

and the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.4.2.2.4 against the SRP-LR Section 3.4.2.2.4 criteria.

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(1) In LRA Section 3.4.2.2.4, the applicant stated that reduction of heat transfer due to

fouling could occur for stainless steel and copper alloy heat exchanger tubes exposed to

treated water. The S&PC system at JAFNPP has no heat exchanger tubes with an

intended function of heat transfer and associated aging effect of fouling. However,

reduction of heat transfer is managed by the Water Chemistry Control - BWR Program

for copper alloy heat exchanger tubes in the high pressure coolant injection system. The

effectiveness of the Water Chemistry Control - BWR Program will be confirmed by the

One-Time Inspection Program through an inspection of a representative sample of

components crediting this program including susceptible locations such as areas of

stagnant flow.

However, the applicant stated-that the S&PCsystem at JAFNPP have no heat

exchanger tubes with an intended function of heat transfer and associated aging effect

of fouling. This item is not applicable to S&PC system at JAFNPP. The applicant also

stated in the discussion column of the Table 3.4.1 that there are no stainless steel heat

exchanger tubes exposed to treated water in the S&PC system. The components to

which this line item applies are in the high pressure coolant injection system in

Table 3.2.2-4.

On the basis that JAFNPP does not have stainless steel heat exchanger tubes exposed

to treated water in the S&PC system subject to this aging effect, the staff finds that this

further evaluation is not applicable to JAFNPP.

(2) In LRA Section 3.4.2.2.4, the applicant stated that reduction of heat transfer due to

fouling could occur for steel, stainless steel, and copper alloy heat exchanger tubes

exposed to lubricating oil. However, the applicant stated that the S&PC system at

JAFNPP have no heat exchanger tubes with an intended function of heat transfer and

associated aging effect of fouling. This item is not applicable to JAFNPP.

The applicant also stated in the discussion column of the Table 3.4.1 that there are no

steel, stainless steel or copper alloy heat exchanger tubes exposed to lubricating oil with

intended functions in the S&PC system.

The staff verified that there are no Table 2 line items in the S&PC system that reference

Table 3.4.1, Item 3.4.1-10.

On the basis that JAFNPP does not have any components from this group in the steam and

power system, the staff found that for this component type, this aging effect/mechanism is not

applicable to JAFNPP.

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.4.2.2.5 against the SRP-LR Section 3.4.2.2.5 criteria.

(1) In LRA Section 3.4.2.2.5, the applicant stated that loss of material due to general,

pitting, and crevice corrosion and MIC could occur in carbon steel (with or without

coating or wrapping) piping, piping components, piping elements and tank exposed to

soil. The S&PC system at JAFNPP have no carbon steel components that are exposed

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to soil. This item is not applicable to JAFNPP.

The staff verified that there are no Table 2 line items in the S&PC system that reference

Table 3.4.1, Item 3.4.1-11. On the basis that JAFNPP does not have any components

from this group in the steam and power system, the staff finds that for this component

type, this aging effect is not applicable to JAFNPP.

(2) In LRA Section 3.4.2.2.5, the applicant stated that loss of material due to general,

pitting, and crevice corrosion and MIC for carbon steel heat exchanger components

exposed to lubricating oil is an aging effect requiring management in the S&PC system

at JAFNPP and is managed by the Oil Analysis Program. This program includes periodic

sampling and analysis of lubricating oil to maintain contaminants within acceptable

limits, thereby preserving an environment that is not conducive to corrosion. During the

past five years, many visual inspections of components containing lubricating oil have

been performed during corrective and preventive maintenance activities. The visual

inspections of these components would identify degraded conditions such as fouling,

corrosion or cracking that could be attributed to an ineffective. Oil Analysis Program.

These past inspections at JAFNPP serve in lieu of a one-time inspection to provide

confirmation of the effectiveness of the Oil Analysis Program.

SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting and crevice

corrosion, and MIC could occur in steel heat exchanger components exposed to

lubricating oil. The existing AMP relies on the periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil contaminant control should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage corrosion to verify the effectiveness of the lube oil chemistry

control program. A one-time inspection of selected components at susceptible locations

is an acceptable method to ensure that corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

operation.

In the discussion column of Table 3.4.1, item 3.4.1-12, the applicant stated that loss of

material in steel heat exchanger components exposed to lubricating oil is managed by

the Oil Analysis Program. The components to which this GALL Report line item applies

are included in-scope under criterion 10 CFR 54.4(a)(2) and listed in Table 3.3.2-14-42.

However, for those line items in Table 3.3.2-14-42 where these Table 3.4.1 line items

are referenced in the S&PC System, only the Oil Analysis Program is credited under

Aging Management Programs.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is

documented in SER Section 3.0.3.2.14. The staff determined that this program includes

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits. The staff finds that these activities are consistent with the

recommendations in GALL Report, and are adequate to manage loss of material due to

general, pitting, and crevice corrosion for steel piping, piping components, and piping

elements exposed to lubricating oil.

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During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection AMP.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection

Program AMP. In its letter dated February 1, 2007 (Amendment 5 to the LRA), the

applicant revised the LRA Section 3.4.2.2.5, item 2, to state that "One time Inspection

Program activities will be utilized to confirm the effectiveness of the Oil Analysis

Program." The staff finds that the use of the one-time inspection to verify the

effectiveness of the oil analysis program is consistent with the recommendations in

GALL Report, and is acceptable. The staff concludes that this AMP will assure detection

of leakage before the loss of its intended function and that this AMP will adequately

manage loss of material due to general, pitting, crevice, and MIC in steel heat

exchanger components exposed to lubricating oil.

Based on the programs identified above, the staff finds that the applicant has met the criteria of

SRP-LR Section 3.4.2.2.5 for further evaluation. For those line items that apply to LRA

Section 3.4.2.2.5, the staff determines that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6.

In LRA Section 3.4.2.2.6, the applicant stated that cracking due to SCC in stainless steel

components exposed to steam or treated water is managed by the Water Chemistry Control -

BWR Program. The effectiveness of the Water Chemistry Control - BWR Program will be

confirmed by the One-Time Inspection Program through an inspection of a representative

sample of components crediting this program including susceptible locations such as areas of

stagnant flow.

SRP-LR Section 3.4.2.2.6 states that cracking due to SCC could occur in the stainless steel

piping, piping components, piping elements, tanks, and heat exchanger components exposed

-to treated water greater than 60 0C (>140 OF), and for stainless steel piping, piping components,

and piping elements exposed to steam. The existing AMP relies on monitoring and control of

water chemistry to manage the effects of cracking due to SCC. However, high concentrations of

impurities at crevices and locations of stagnant flow conditions could cause SCC. Therefore,

the GALL Report recommends that the effectiveness of the Water Chemistry Control Program

should be verified to ensure that SCC is not occurring. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that SCC is not

occurring and that the component's intended function will be maintained during the period of

extended operation.

In the discussion column of Table 3.4.1, items 3.4.1-13 and 3.4.1-14, the applicant stated that

the One-Time Inspection Program will- be used to verify the effectiveness of the Water

Chemistry Control - BWR Program. However, for those line items in Tables 3.2.2-4, 3.2.2-5,

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3.2.2-6, 3.3.2-14-1, 3.3.2-14-7, 3.3.2-14-14, 3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20,

3.3.2-14-21, and 3.3.2-14-44, where these Table 3.4.1 line items are referenced in the S&PC

System, only the Water Chemistry Control - BWR Program is credited under Aging

Management Programs, but a note "401" is included to indicate that the effectiveness of the

Water Chemistry Control - BWR Program will be verified by the One-Time Inspection Program.

The staff determined that the use of One-Time Inspection Program to verify the effectiveness of

the Water Chemistry Control Program is consistent with the recommendations in GALL Report,

and is acceptable.

The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time

Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.10 and

3.0.3.1.6, respectively. The staff determined that these programs include activities that are

consistent with the recommendations in GALL Report, and are adequate to manage cracking

due to SCC. On the basis that One-Time Inspection will be performed on the components, the

staff determined that the Water Chemistry Control - BWR Program is appropriate for the AEMs

identified and provides assurance that the AEMs will be effectively managed through the period

of extended operation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.4.2.2.6 for further evaluation. For those line items that apply to

LRA Section 3.4.2.2.6, the staff determines that the LRA is consistent with the GALL Report

and the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.7 against the SRP-LR Section 3.4.2.2.7 criteria.

(1) In LRA Section 3.4.2.2.7, the applicant stated that loss of material due to pitting and

crevice corrosion for stainless steel components exposed to treated water is managed

by the Water Chemistry Control - BWR Program. The S&PC system at JAFNPP have

no aluminum or copper alloy components with intended functions that are exposed to

treated water. The effectiveness of the Water Chemistry Control - BWR Program will be

confirmed by the One-Time Inspection Program through an inspection of a

representative sample of components crediting this program including susceptible

locations such as areas of stagnant flow.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion could occur for stainless steel, aluminum, and copper alloy piping, piping

components and piping elements and for stainless steel tanks and heat exchanger

components exposed to treated water. The existing AMP relies on monitoring and

control of water chemistry to manage the effects of loss of material due to pitting, and

crevice corrosion. However, control of water chemistry does not preclude corrosion at

locations of stagnant flow conditions. Therefore, the GALL Report recommends that the

effectiveness of the water chemistry program should be verified to ensure that corrosion

is not occurring. A one-time inspection of select components at susceptible locations is

an acceptable method to ensure that corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

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operation.

In the discussion column of Table 3.4.1, item 3.4.1-15, the applicant stated that there

are no aluminum or copper alloy components with intended functions in the S&PC

system. The staff verified that there are no Table 2 line items in the S&PC system that

reference Table 3.4.1, Item 3.4.1-15. On the basis that JAFNPP does not have any

components from this group in the steam and power system, the staff found that for this

component type, this aging effect/mechanism is not applicable to JAFNPP.

In the discussion column of Table 3.4.1, item 3.4.1-16, the applicant stated that the

One-Time Inspection Program will be used to verify the effectiveness of the Water

Chemistry Control - BWR Program. The applicant used Note "401" in Tables 3.4.2-1,

3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, and 3.3.2-14-21 where these

Table 3.4.1 line items are referenced in the S&PC system to indicate that the

effectiveness of the Water Chemistry Control - BWR Program will be verified by the

One-Time Inspection Program.

The staff reviewed the applicant's Water Chemistry Control - BWR Program and

One-Time Inspection Program and its evaluations are documented in SER

Sections 3.0.3.1.10 and 3.0.3.1.6, respectively. The staff determined that these

programs include activities that are consistent with the recommendations in GALL

Report, and are adequate to manage loss of material due to pitting and crevice

corrosion in stainless steel components exposed to treated water. The staff concluded

that these AMPs will adequately manage loss of material due to pitting and crevice

corrosion for stainless steel components exposed to treated water. On the basis that

one-time inspection will be performed on the components to verify the effectiveness of

Water Chemistry Control - BWR Program, the staff determined that the Water

Chemistry Control - BWR Program is appropriate for the AEMs identified and provides

assurance that the AEMs will be effectively managed through the period of extended

operation.

Based on the programs identified above, the staff finds that the applicant has met the

criteria of SRP-LR Section 3.4.2.2.7, Item 1, for further evaluation.

(2) In LRA Section 3.4.2.2.7, the applicant stated that loss of material due to pitting and

crevice corrosion for stainless steel piping and piping components exposed to soil

environment is managed by the Buried Piping and Tanks Inspection Program. The

Buried Piping and Tanks Inspection Program will include (a) preventive measures to

mitigate corrosion and (b) inspections to manage the effects of corrosion on the

pressure-retaining capability of buried carbon steel, copper alloy, gray cast iron,

stainless steel components. Buried components will be inspected when excavated

during maintenance. An inspection will be performed within ten years of entering the

period of extended operation, unless an opportunistic inspection occurred within this

ten-year period.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion could occur for stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that this aging effect is adequately managed. Acceptance criteria are

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described in Appendix A.1 of SRP-LR Branch Technical Position RLSB -1.

In the discussion column of Table 3.4.1, item 3.4.1-17, the applicant stated that the

Buried Piping and Tanks Inspection Program manages loss of material in stainless steel

components exposed to soil.

The staff reviewed the applicant's Buried Piping and Tanks Inspection Program and its

evaluation is documented in SER Section 3.0.3.2.1. The staff determined that this

program's opportunistic or focused inspections of buried components are consistent with

the recommendations in GALL Report, and are adequate to manage loss of material

due to pitting and crevice corrosion for stainless steel piping and piping components

exposed to soil environment. The staff confirmed that inspections will be performed both

during the 10-year period immediately prior to the period of extended operation, as well

as during the 10-year period after entering the period of extended operation, which is

consistent with recommendations in GALL Report. On this basis, the staff finds that the

applicant has met the criteria of SRP-LR Section 3.4.2.2.7, Item 2, for further evaluation.

(3) In LRA Section 3.4.2.2.7, the applicant stated that loss of material due to pitting and

crevice corrosion for copper alloy piping and components exposed to lubricating oil is

managed by the Oil Analysis Program, which includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. During the past five years, many visual

inspections of components containing lubrication oil have been performed during

corrective and preventive maintenance activities. The visual inspections of these

components would identify degraded conditions such as fouling, corrosion, or cracking

that could be attributed to an ineffective Oil Analysis Program. These past inspections at

JAFNPP serve in lieu of a one time inspection to provide confirmation of the

effectiveness of the Oil Analysis Program.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion could occur for copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP relies on the periodic sampling and analysis

of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil contaminant control should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage corrosion to verify the effectiveness of the lube oil chemistry

control program. A one-time inspection of selected components at susceptible locations

is an acceptable method to ensure that corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

operation.

In the discussion section of Table 3.4.1, item 3.4.1-18, the applicant stated that loss of

material in copper alloy components exposed to lubricating oil is managed by the Oil

Analysis Program. The components to which this GALL Report line item applies are

included in-scope under criterion 10 CFR 54.4(a)(2) and listed in Table 3.3.2-14-26.

However, for those line items in Table 3.3.2-14-26 where this Table 3.4.1 line item is

referenced in the Turbine Lube Oil System, only the Oil Analysis Program is credited

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under Aging Management Programs.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is

documented in SER Section 3.0.3.2.14. The staff determined that this program includes

periodic sampling and analysis of lubricating oil to maintain contaminants within

acceptable limits. The staff finds that these activities are consistent with the

recommendations in GALL Report, and are adequate to manage loss of material due to

pitting and crevice corrosion for copper alloy piping and components exposed to

lubricating oil.

During the audit and review, the staff asked the applicant to clarify whether the

inspections credited in lieu of the one-time inspection are consistent with the GALL

Report recommendations for the One-Time Inspection Program AMP. The staff's

evaluation of the One-Time Inspection Program is documented in SER

Section 3.0.3.1.6.

In its response, the applicant stated that the LRA will be amended to add activities to

confirm the effectiveness of the Oil Analysis Program to the One-Time Inspection AMP.

In its letter dated February 1, 2007 (Amendment 5 to the LRA), the applicant revised the

LRA Section 3.4.2.2.7, item 3, to state that "One time Inspection Program activities will

be utilized to confirm the effectiveness of the Oil Analysis Program." The staff finds that

the use of the one-time inspection to verify the effectiveness of the oil analysis program

is consistent with the recommendations in GALL Report, and is acceptable.

The staff concludes that Oil Analysis Program and One-Time Inspection Program will

assure detection of leakage before the loss of its intended function and that these AMPs

will adequately manage loss of material of copper alloy piping, piping components, and

piping elements exposed to lubricating oil

Based on the programs identified above, the staff finds that the applicant has met the criteria of

SRP-LR Section 3.4.2.2.7. For those line items that apply to LRA Section 3.4.2.2.7, the staff

determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8.

In LRA Section 3.4.2.2.8, the applicant stated that loss of material due to pitting, crevice, and

MIC in stainless steel piping and components exposed to lubricating oil is managed by the Oil

Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits, thereby preserving an environment that is not conducive

to corrosion. During the past five years, many visual inspections of components containing

lubricating oil have been performed during corrective and preventive maintenance activities.

The visual inspections of these components would identify degraded conditions such as fouling,

corrosion, or cracking that could be attributed to an ineffective Oil Analysis Program. These

past inspections at JAFNPP serve in lieu of a one-time inspection to provide confirmation of the

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effectiveness of the Oil Analysis Program. The S&PC system at JAFNPP have no stainless

steel heat exchanger components exposed to lubricating oil.

SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting, crevice, and MIC could

occur in stainless steel piping, piping components, piping elements, and heat exchanger

components exposed to lubricating oil. The existing AMP relies on the periodic sampling and

analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving

an environment that is not conducive to corrosion. However, control of lubricating oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion is

not occurring. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lubricating oil chemistry control program. A one-time

inspection of selected components at susceptible locations is an acceptable method to ensure

that corrosion is not occurring and that the component's intended function will be maintained

during the period of extended operation.

The staff reviewed the applicant's Oil Analysis Program and its evaluation is documented in

SER Section 3.0.3.2.14. The staff determined that this program includes periodic sampling and

analysis of lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in GALL Report, and are adequate to

manage loss of material due to general, pitting, and crevice corrosion for steel piping, piping

components, and piping elements exposed to lubricating oil.

In the discussion column of Table 3.4.1, item 3.4.1-19, the applicant stated that the loss of

material in stainless steel components exposed to lubricating oil is managed by the Oil Analysis

Program. The components to which this GALL Report line item applies are included in-scope

under criterion 10 CFR 54.4(a)(2) and listed in Table 3.3.2-14-42. However, for those line items

in Table 3.3.2-14-42 where this Table 3.4.1 line item is referenced in the Main Turbine

Generator System, only the Oil Analysis Program is credited under Aging Management

Programs

During the audit and review, the staff asked the applicant to clarify whether the inspections

credited in lieu of the one-time inspection are consistent with the GALL Report

recommendations for the One-Time Inspection Program AMP.

In its response, the applicant stated that the LRA will be amended to add activities to confirm

the effectiveness of the Oil Analysis Program to the One-Time Inspection Program AMP. The

staff's evaluation of the One-Time Inspection Program is documented in SER Section 3.0.3.1.6.

In its letter dated February 1, 2007 (Amendment 5 to the LRA), the applicant revised the LRA

Section 3.4.2.2.8 to state that "One time Inspection Program activities will be utilized to confirm

the effectiveness of the Oil Analysis Program." The staff finds that the use of the one-time

inspection to verify the effectiveness of the oil analysis program is consistent with the

recommendations in GALL Report, and is acceptable.

Based on the programs identified above, the staff finds that the applicant has met the criteria of

SRP-LR Section 3.4.2.2.8. For those line items that apply to LRA Section 3.4.2.2.8, the staff

determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

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required by 10 CFR 54.21(a)(3).

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9.

In LRA Section 3.4.2.2.9, the applicant stated that loss of material due to general, pitting,

crevice, and galvanic corrosion for steel heat exchanger components exposed to treated water

is managed by the Water Chemistry Control - BWR Program. The effectiveness of the Water

Chemistry Control - BWR Program will be confirmed by the One-Time Inspection Program

through an inspection of a representative sample of components crediting this program

including susceptible locations such as areas of .stagnant flow.

SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, and

galvanic corrosion can occur for steel heat exchanger components exposed to treated water.

The existing AMP relies on monitoring and control of water chemistry to manage the effects of

loss of material due to general, pitting, and crevice corrosion. However, control of water

chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at

locations of stagnant flow conditions. Therefore, the effectiveness of the Water Chemistry

Control Program should be verified to ensure that corrosion is not occurring. The GALL Report

recommends further evaluation of programs to verify the effectiveness of the Water Chemistry

Control Program. A one-time inspection of select components at susceptible locations is an

acceptable method to ensure that corrosion is not occurring and that the component's intended

function will be maintained during the period of extended operation.

In the discussion section of Table 3.4.1, item 3.4.1-5, the applicant stated that the program is

consistent with GALL Report. Loss of material in steel heat exchanger components exposed to

treated water is managed by the Water Chemistry Control - BWR Program. The One-Time

Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.

The components to which this GALL Report line item applies are included in-scope under

criterion 10 CFR 54.4(a)(2) and listed in Table 3.3.2-14-17 and Table 3.3.2-14-19. The

applicant used Note "401" for those line items in Tables 3.3.2-14-17 and 3.3.2-14-19 where

these Table 3.4.1 line items are referenced in the Extraction Steam and Condensate System to

indicate that the effectiveness of the Water Chemistry Control - BWR Program will be verified

by the One-Time Inspection Program.

The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time

Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.10 and

3.0.3.1.6, respectively. The staff verified that Water Chemistry Control - BWR Program

included activities that monitor and control water chemistry to manage the effects of loss of

material due to general, pitting, crevice, and galvanic corrosion for steel heat exchanger

components exposed to treated water. In addition, the staff verified that the One-Time

Inspection Program included inspection activities to verify the effectiveness of Water Chemistry

Control Program to manage loss of material due to general, pitting, and crevice corrosion at

locations of stagnant flow conditions. On the basis that one-time inspection will be performed on

the components to verify the effectiveness of Water Chemistry Control-BWR Program, the staff

concluded that these programs will adequately manage loss of material due to general, pitting,

crevice, and galvanic corrosion for steel heat exchanger components exposed to treated water.

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Based on the programs identified above, the staff finds that the applicant has met the criteria of

SRP-LR Section 3.4.2.2.9. For those line items that apply to LRA Section 3.4.2.2.9, the staff

determines that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.

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

Summary of Technical Information in the Application. In LRA Tables 3.4.2-1, 3.3.2-14-16,

3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, 3.3.2-14-21, 3.3.2-14-22, 3.3.2-14-42, and 3.3.2-14-44

the staff reviewed additional details concerning the results of the AMRs for material,

environment, AERM, and AMP combinations that are not consistent with the GALL Report, or

that are not addressed in the GALL Report.

In LRA Tables 3.4.2-1, 3.3.2-14-16, 3.3.2-14-17, 3.3.2-14-19, 3.3.2-14-20, 3.3.2-14-21,

3.3.2-14-22, 3.3.2-14-42, and 3.3.2-14-44, the applicant indicated, via notes F through J, that

the combination of component type, material, environment, and AERM does not correspond to

a line item in the GALL Report. The applicant provided further information concerning how the

aging effects will be managed. Specifically, note F indicates that the material for the AMR line

item component is not evaluated in the GALL Report. Note G indicates that the environment for

the AMR line item component and material is not evaluated in the GALL Report. Note H

indicates that the aging effect for the AMR line item component, material, and environment

combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified

in the GALL Report for the line item component, material, and environment combination is not

applicable. Note J indicates that neither the component nor the material and environment

combination for the line item is evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

3.4.2.3.1 Condensate Storage System Summary of Aging Management Evaluation -

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 storage system component groups.

LRA Table 3.4.2-1 states that the AMR line items for the condensate storage system are

consistent with the GALL Report with the exception of three line items. Two line items consist of

stainless steel material and component type - tank, piping, and screen exposed to air-outdoor

(external) and one line item consists of stainless steel material and component type - screen

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and piping exposed to condensation (internal). The AMR line items cite Generic Note G, which

indicates that the environment is not addressed in GALL Report for this component and

material combination. In LRA Table 3.4.2-1, the applicant proposed to manage loss of material

for stainless steel components types exposed to air-outdoor (external) environment using

External Surfaces Monitoring Program and Bolting Integrity Program.

The staff reviewed the applicant's External Surfaces Monitoring Program and Bolting Integrity

Program and its evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.2.20,

respectively. The staff determined that these programs include a periodic visual inspection of

components that will be effective for detecting loss of material. These programs are consistent

with GALL AMPs XI.M36 and XI.M18, respectively and are adequate to manage loss of material

for stainless steel components types exposed to air-outdoor (external) environment. On this

basis, the staff finds-the AMR results for these line items acceptable.

In LRA Table 3.4.2-1, the applicant proposed to manage loss of material for stainless steel

components exposed to condensation (internal) environment using Water Chemistry Control -

BWR Program. The AMR line item cites Generic Note G, which indicates that the environment

is not addressed in GALL Report for this component and material combination. The staff

reviewed the applicant's Water Chemistry Control-BWR Program and its evaluation is

documented in SER Section 3.0.3.1.10. The staff determined that this program includes

activities that are consistent with the recommendations in GALL Report, and are adequate to

manage loss of material for stainless steel components due to pitting and crevice corrosion

exposed to environment such as treated water and condensation (internal). On this basis,. the

staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.2 Main Steam System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-16

The staff reviewed LRA Table 3.3.2-14-16, which summarizes the results of AMR evaluations

for the main steam system component groups. LRA Table 3.3.2-14-16 states that the AMR line

items for the main steam system are consistent with the GALL Report with the exception of two

line items. The two line items consist of stainless steel material and component type tubing and

thermowell exposed to steam (internal). The applicant identified TLAA - metal fatigue as aging

effect requiring management.

SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

For other line items the staff confirmed that the AMR results presented in this table are

consistent with the GALL Report. The staff's evaluation for AMR items that are consistent with

the GALL Report is documented in SER Section 3.4.2.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

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aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.3 Extraction Steam System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-17

The staff reviewed LRA Table 3.3.2-14-17, which summarizes the results of AMR evaluations

for the extraction steam system component groups.

LRA Table 3.3.2-14-17 states that the AMR results for the extraction steam system are

consistent with the GALL Report with the exception of six line items. The six line items consist

of stainless steel material and component type tubing, valve body, orifice, thermowell, flow

element, and expansion joint exposed to steam (int). The applicant identified TLAA - metal

fatigue as aging effect requiring management.

SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

For other line items the staff confirmed that the AMR results presented in this table are

consistent with the GALL Report. The staff's evaluation for AMR line items that are consistent

with the GALL Report is documented in SER Section 3.4.2.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.4 Condensate System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-19

The staff reviewed LRA Table 3.3.2-14-19, which summarizes the results of AMR evaluations

for the condensate system component groups.

LRA Table 3.3.2-14-19 states that the AMR results for the condensate system are consistent

with the GALL Report with the exception of seven line items. Three line items are identified with

stainless steel material, and component types - piping, bolting, and orifice exposed to

air-outdoor (external) environment. The AMR line items cite Generic Note G, which indicates

that the environment is not addressed in GALL Report for this component and material

combination. The applicant identified loss of material as the aging effect requiring management

and the External Surfaces Monitoring Program (for stainless steel, components types - piping

and orifices) and Bolting Integrity Program (for stainless steel components type - bolting) as the

programs for managing the aging effect.

The staff reviewed the applicants External Surfaces Monitoring Program and Bolting Integrity

Program and its evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.2.20,

respectively. The staff determined that these programs include a periodic visual inspection of

components that will be effective for detecting loss of material. On this basis, the staff finds the

AMR results for these line items acceptable.

The other four line items consist of stainless steel material, component type - tubing, piping,

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valve body, and thermowell exposed to steam (internal) environment. The applicant identified

cracking-fatigue as the aging effect requiring management. The applicant proposed to manage

cracking-fatigue for these components using TLAA - metal fatigue. The staff reviewed the

applicant's TLAA on Metal Fatigue of Non-Class 1 Components in LRA Section 4.3.2. SER

Section 4.3.2 documents the staff's review of the applicant's evaluation of this TLAA.

For other line items, the staff confirmed that the AMR results presented in this table are

consistent with the GALL Report. The staff's evaluation for AMR items that are consistent with

the GALL Report is documented in SER Section 3.4.2.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the.GALL Report. The staff finds that the applicant-has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.5 Feedwater System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-20

The staff.reviewed LRA Table 3.3.2-14-20, which summarizes the results of AMR evaluations

for the feedwater system nonsafety-related component groups affecting safety-related systems

and determined that the applicant did not include any AMR results with Generic Notes F

through J involving material environment, AERMs, and AMP combinations that are not

evaluated in the GALL Report.

3.4.2.3.6 Feedwater Heater, Vents, and Drains System, Nonsafety-Related Components

Affecting Safety-Related Systems Summary of Aging Management Evaluation -

LRA Table 3.3.2-14-21

The staff reviewed LRA Table 3.3.2-14-21, which summarizes the results of AMR evaluations

for the feedwater heater, vents, and drains system nonsafety-related component groups

affecting safety-related systems. LRA Table 3.3.2-14-21 states that the AMR results for the

feedwater heater vents and drains system are consistent with the GALL Report with the

exception of three line items. The three line items consist of stainless steel material and

component type - tubing, orifice, and thermowell exposed to steam (internal). The applicant

identified TLAA - metal fatigue as aging effect requiring management.

SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

For other line items the staff confirmed that the AMR results presented in this table are

consistent with the GALL Report. The staff's evaluation for AMR line items that are consistent

with the GALL Report is documented in SER Section 3.4.2.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated

in the GALL Report. The staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.7 Circulating Water System, Nonsafety-Related Components Affecting Safety-Related

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Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-22

The staff reviewed LRA Table 3.3.2-14-22, which summarizes the results of AMR evaluations

for the circulating water system nonsafety-related component groups affecting safety-related

systems and determined that the applicant did not include any AMR results with Generic Notes

F through J involving material environment, AERMs, and AMP combinations that are not

evaluated in the GALL Report.

3.4.2.3.8 Main Turbine Generator, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-42

The staff reviewed LRA Table 3.3.2-14-42, which summarizes the results of AMR evaluations

for the main turbine generator circulating water system nonsafety-related component groups

affecting safety-related systems and determined that the applicant did not include any AMR

results with Generic Notes F through J involving material environment, AERMs, and AMP

combinations that are not evaluated in the GALL Report.

3.4.2.3.9 Steam Seal System, Nonsafety-Related Components Affecting Safety-Related

Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-14-44

The staff reviewed LRA Table 3.3.2-14-44, which summarizes the results of AMR evaluations

for the Steam Seal System nonsafety-related component groups affecting safety-related

systems. LRA Table 3.3.2-14-44 states that the AMR results for the Steam Seal System are

consistent with the GALL Report with the exception of one line item. The one line item consists

of stainless steel material and component type - tubing exposed to steam (internal). The

applicant identified TLAA - metal fatigue as the aging effect requiring management.

SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

For other line items the staff confirmed that the AMR results presented in this table are

consistent with the GALL Report. The staff's evaluation for AMR line items that are consistent

with the GALL Report is documented in SER Section 3.4.2.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 S&PC system components, that are within the scope of license

renewal and subject to an AMR, will be adequately managed so that the intended function(s)

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.5 Aaina Manauement 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 the following:

* reactor building and primary containment

• water control structures

• turbine building complex and yard structures

• bulk commodities

3.5.1 Summary of Technical Information in the Application

In LRA Section 3.5, the applicant provided AMR results for the structures and component

supports components and component groups. In LRA Table 3.5.1, "Summary of Aging

Management Programs for the Structures and Component Supports," the applicant provided a

summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the

structures and component supports components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of 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, that are 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 confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.5.2.1.

In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.5.2.2. The staff's

audit evaluations are documented in SER Section 3.5.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

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effects listed were appropriate for the combination of materials and environments specified. The

staff's audit evaluations are documented in SER Section 3.5.2.3. The staff's evaluation of the

technical review is also documented in SER Section 3.5.2.3.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the structures and component supports components.

Table 3.5-1, provided below, includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.5, that are addressed in the GALL

Report.

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

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

BWR Concrete and Steel (Mark I, II, and Ill) Containments

Concrete elements: Aging of accessible ISI (IWL) and for Not applicable (See

walls, dome, and inaccessible inaccessible N/A SER

basemat, ring concrete areas due concrete, an Section 3.5.2.2.1)

girder, buttresses, to aggressive examination of

containment chemical attack, representative

(as applicable), and corrosion of samples of

(3.5.1-1) embedded steel below-grade

concrete, and

periodic monitoring

of groundwater if

environment is

non-aggressive. A

plant-specific

program is to be

evaluated if

environment is

aggressive.

Concrete elements; Cracks and Structures N/A Not applicable (See

All distortion due to Monitoring SER

(3.5.1-2) increased stress Program. If a Section 3.5.2.2.1)

levels from de-watering system

settlement 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.

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Component Group Aging Effect/ AMP.in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

- Item No.)

Concrete elements: Reduction in Structures Not applicable (See

foundation, foundation strength, Monitoring Program N/A SER

sub-foundation cracking, differential If a de-watering Section 3.5.2.2.1)

(3.5.1-3) settlement due to system is relied

erosion of porous upon to control

concrete erosion of cement

subfoundation from porous

concrete

subfoundations,

then the licensee is

to ensure proper

functioning of the

de-watering system

through the period

of extended

operation.

Concrete elements: Reduction of A plant-specific N/A Not applicable (See

dome, wall, strength and aging management SER

basemat, ring modulus of program is to be Section 3.5.2.2.1)

girder, buttresses, concrete due to evaluated

containment, elevated

concrete fill-in temperature

annulus

(as applicable)

(3.5.1-4)

Steel elements: Loss of material ISI (IWE) and Containment Consistent with

Drywell; torus; due to general, 10 CFR Part 50, Inservice Inspection GALL Report, which

drywell head; pitting and crevice Appendix J (CII) and recommends further

embedded shell corrosion Containment Leak evaluation (See

and sand pocket Rate program SER

regions; drywell Section 3.5.2.2.1)

support skirt; torus

ring girder;

downcomers; liner

plate, ECCS suction

header, support

skirt, region

shielded by

diaphragm floor,

suppression

chamber

(as applicable)

(3.5.1-5)

Steel elements: Loss of material ISI (IWE) and N/A Not applicable (See

steel liner, liner due to general, 10 CFR Part 50, SER

anchors, integral pitting and crevice Appendix J Section 3.5.2.2.1)

attachments corrosion

(3.5.1-6)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Prestressed Loss of prestress TLAA, evaluated in N/A Not applicable (See

containment due to relaxation, accordance with SER

tendons shrinkage, creep, 10 CFR 54.21(c) Section 3.5.2.2.1)

(3.5.1-7) and elevated

temperature

Steel and stainless Cumulative fatigue TLAA, evaluated in TLAA - Metal fatigue Consistent with

steel elements: vent damage (CLB accordance with GALL Report, which

line, vent header, fatigue analysis 10 CFR 54.21(c) recommends further

vent line bellows; exists) evaluation (See

downcomers; SER-..

(3.5.1-8) Section 3.5.2.2.1)

Steel, stainless Cumulative fatigue TLAA, evaluated in TLAA - Metal fatigue Consistent with

steel elements, damage (CLB accordance with GALL Report, which

dissimilar metal. fatigue analysis 10 CFR 54.21(c) recommends further

welds: penetration exists) evaluation (See

sleeves, penetration SER

bellows; Section 3.5.2.2.1)

suppression pool

shell, unbraced

downcomers

(3.5.1-9)

Stainless steel Cracking due to ISi (IWE) and Containment Consistent with

penetration sleeves, stress corrosion 10 CFR Part 50, Inservice Inspection GALL Report, which

penetration bellows, cracking Appendix J, and (CII) and recommends further

dissimilar metal additional Containment Leak evaluation (See

welds appropriate Rate program SER

(3.5.1-10) examinations/ Section 3.5.2.2.1)

evaluations for

bellows assemblies

and dissimilar

metal.welds.

Stainless steel vent Cracking due to ISI (IWE) and Containment Consistent with

line bellows, stress corrosion 10 CFR Part 50, Inservice Inspection GALL Report, which

(3.5.1-11) cracking Appendix J, and (CII) and recommends further

additional Containment Leak evaluation (See

appropriate Rate program SER

examination/ Section 3.5.2.2.1)

evaluation for

bellows assemblies

and dissimilar

metal welds.

Steel, stainless Cracking due to ISI (IWE) and Containment Consistent with

steel elements, cyclic loading 10 CFR Part 50, Inservice Inspection GALL Report, which

dissimilar metal Appendix J, and (CII) and recommends further

welds: penetration supplemented to Containment Leak evaluation (See

sleeves, penetration detect fine cracks Rate program SER

bellows; Section 3.5.2.2.1)

suppression pool

shell, unbraced

downcomers

(3.5.1-12)

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel, stainless Cracking due to ISI (IWE) and Containment Consistent with

steel elements, cyclic loading 10 CFR Part 50, Inservice inspection GALL Report, which

dissimilar metal Appendix J, and (CII) and recommends further

welds: torus; vent supplemented to Containment Leak evaluation (See

line; vent header; detect fine cracks Rate program SER

vent line bellows; Section 3.5.2.2.1)

downcomers

(3.5.1-13)

Concrete elements: Loss of material ISI (IWL). None Consistent with

dome, wall, (Scaling, cracking, Evaluation is GALL Report, which

basemat ring girder, and spalling) due to needed for plants recomrnmends further

buttresses, freeze-thaw that are located in evaluation (See

containment moderate to severe SER

(as applicable) weathering Section 3.5.2.2.1)

(3.5.1-14) conditions

(weathering

index > 100

day-inch/yr)

(NUREG-1557).

Concrete elements: Cracking due to ISI (IWL) for None Consistent with

walls, dome, expansion and accessible areas. GALL Report, which

basemat, ring reaction with None for recommends further

girder, buttresses, aggregate; increase inaccessible areas evaluation (See

containment, in porosity, if concrete was SER

concrete fill-in permeability due to constructed in Section 3.5.2.2.1)

annulus leaching of calcium accordance with

(as applicable), hydroxide the

(3.5.1-15) recommendations

in ACI 201.2R.

Seals, gaskets, and Loss of sealing and ISI (IWE) and Structures Consistent with

moisture barriers leakage through 10 CFR Part 50, Monitoring Program, GALL Report, which

(3.5.1-16) containment due to Appendix J Containment recommends no

deterioration of joint Inservice Inspection, further evaluation

seals, gaskets, and and Containment (See SER

moisture barriers Leak Rate program Section 3.5.2.1.1)

(caulking, flashing,

and other sealants)

Personnel airlock, Loss of leak 10 CFR Part 50, Containment Consistent with

equipment hatch tightness in closed Appendix J and Inservice Inspection GALL Report, which

and CRD hatch position due to Plant Technical (CII) and recommends no

locks, hinges, and mechanical wear of Specifications Containment Leak further evaluation

closure locks, hinges and Rate program (See SER

mechanisms closure Section 3.5.2.1)

(3.5.1-17) mechanisms

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Steel penetration Loss of material ISI (IWE) and Containment Consistent with

sleeves and due to general, 10 CFR Part 50; Inservice Inspection GALL Report, which

dissimilar metal pitting, and crevice Appendix J (CII) and recommends no

welds; personnel corrosion Containment Leak further evaluation

airlock, equipment Rate program (See SER

hatch and CRD Section 3.5.2.1.2)

hatch

(3.5.1-18)

Steel elements: Cracking due to ISI (IWE) and N/A Not applicable (See stainless steel i stress corrosion 10 CFR Part 50, SER

suppression J cracking Appendix J Section 3.5.2.1.9)

chamber shell

(inner surface)

(3.5.1-19)

Steel elements: Loss of material ISI (IWE) and N/A Not applicable (See

suppression due to general, 10 CFR Part 50, SER

chamber liner pitting, and crevice Appendix J Section 3.5.2.1.9)

(interior surface) corrosion

(3.5.1-20)

Steel elements: Fretting or lock up ISI (IWE) Containment Consistent with

drywell head and due to mechanical Inservice Inspection GALL Report, Which

downcomer pipes wear (CII) recommends no

(3.5.1-21) further evaluation

(See SER

Section 3.5.2.1)

Prestressed Loss of material ISI (IWL) N/A Not applicable (See

containment: due to corrosion SER

tendons and Section 3.5.2.1.9)

anchorage

components

(3.5.1-22)

Safety-Related and Other Structures; and Component Supports

All Groups except Cracking, loss of Structures Structures Consistent with

Group 6: interior bond, and loss of Monitoring Program Monitoring Program GALL Report, which

and above grade material (spalling, recommends further

exterior concrete scaling) due to evaluation (See

(3.5.1-23) corrosion of SER

embedded steel Section 3.5.2.2.2)

All Groups except Increase in porosity Structures Structures Consistent with

Group 6: interior and permeability, Monitoring Program Monitoring Program GALL Report, which

and above grade cracking, loss of recommends further

exterior concrete material (spalling, evaluation (See

(3.5.1-24) scaling) due to SER

aggressive Section 3.5.2.2.2)

chemical attack

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All Groups except

Group 6: steel

components: all

structural steel

(3.5.1-25)

Loss of material

due to corrosion

Structures

Monitoring

Program. If

protective coatings

are relied upon to

manage the effects

of aging, the

structures

monitoring program

is to include

provisions to

address protective

coating monitoring

and maintenance.

Structures

Monitoring Program

Consistent with

GALL Report, which

recommends further

evaluation (See

SER

Section 3.5.2.2.2)

All Groups except Loss of material Structures Structures Consistent with

Group 6: accessible (spalling, scaling) Monitoring Monitoring Program GALL Report, which

and inaccessible and cracking due to Program. recommends further

concrete: freeze-thaw Evaluation is evaluation (See

foundation needed for plants SER

(3.5.1-26) that are located in Section 3.5.2.2.2)

moderate to severe

weathering

conditions

(weathering index

> 100 day-inch/yr)

(NUREG-1557).

All Groups except Cracking due to Structures Structures Consistent with

Group 6: accessible expansion due to Monitoring Monitoring Program GALL Report, which

and inaccessible reaction with Program. None for recommends further

interior/exterior aggregates inaccessible areas evaluation (See

concrete if concrete was SER

(3.5.1-27) constructed in Section 3.5.2.2.2)

accordance with

the

recommendations

in ACl 201.2R-77.

Groups 1-3, 5-9: All Cracks and Structures Structures Consistent with

(3.5.1-28) distortion due to Monitoring Monitoring Program GALL Report, which

increased stress Program. If a recommends further

levels from de-watering system evaluation (See

settlement is relied upon for SER

control of Section 3.5.2.2.2)

settlement, then the

licensee is to

ensure proper

functioning of the

de-watering system

through the period

of extended

operation.

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Groups 1-3, 5-9: Reduction in Structures Structures Consistent with

foundation foundation strength, Monitoring Monitoring Program GALL Report, which

(3.5.1-29) cracking, differential Program. If a recommends further

settlement due to de-watering system evaluation (See

erosion of porous is relied upon for SER

concrete control of Section 3.5.2.2.2)

subfoundation settlement, then the

licensee is to

ensure proper

functioning of the

de-watering system

through the period

of extended

operation.

Group 4: Radial Lock-up due to ISI (IWF) or Structures Consistent with

beam seats in BWR wear Structures Monitoring Program GALL Report, which

drywell; RPV Monitoring Program recommends further

support shoes for evaluation (See

PWR with nozzle SER

supports; Steam Section 3.5.2.2.2)

generator supports

(3.5.1-30)

Groups 1-3, 5, 7-9: Increase in porosity Structures Structures Consistent with

below-grade and permeability, monitoring Monitoring Program GALL Report, which

concrete cracking, loss of Program; recommends further

components, such material (spalling, Examination of evaluation (See

as exterior walls scaling)/aggressive representative SER

below grade and chemical attack; samples of Section 3.5.2.2.2)

foundation Cracking, loss of below-grade

(3.5.1-31) bond, and loss of concrete, and

material (spalling, periodic monitoring

scaling)/corrosion of of groundwater, if

embedded steel the environment is

non-aggressive. A

plant-specific

program is to be

evaluated if

environment is

aggressive.

Groups 1-3, 5, 7-9: Increase in porosity Structures Structures Consistent with

exterior above and and permeability, Monitoring Program Monitoring Program GALL Report, which

below grade and loss of strength for accessible recommends further

reinforced concrete due to leaching of areas. None for evaluation (See

foundations calcium hydroxide inaccessible areas SER

(3.5.1-32) if concrete was Section 3.5.2.2.2)

constructed in

accordance with

the

recommendations

in ACI 201.2R-77.

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Groups 1-5: Reduction of A plant-specific Structures Consistent with

concrete strength and aging management Monitoring Program GALL Report, which

(3.5.1-33) modulus due to program is to be recommends further

elevated evaluated evaluation (See

temperature SER

Section 3.5.2.2.2)

Group 6: Concrete; Increase in porosity Inspection of Structures - Consistent with

all and permeability, Water-Control Monitoring Program GALL Report, which

(3.5.1-34) cracking, loss of Structures or recommends further

material due to FERC/US Army evaluation (See

aggressive. -Corps of Engineers SERý

chemical attack; dam inspections Section 3.5.2.2.2)

cracking, loss of and maintenance

bond, loss of programs and for

material due to inaccessible

corrosion of concrete, an

embedded steel examination of

representative

samples of

below-grade

concrete, and

periodic monitoring

of groundwater, if

the environment is

non-aggressive. A

plant-specific

program is to be

evaluated if

environment is

aggressive.

Group 6: exterior Loss of material Inspection of Structures Consistent with

above and below (spalling, scaling) Water-Control Monitoring Program GALL Report, which

grade concrete and cracking due to Structures or recommends further

foundation freeze-thaw FERC/US Army evaluation (See

(3.5.1-35) Corps of Engineers SER

dam inspections Section 3.5.2.2.2)

and maintenance

programs.

Evaluation is

needed for plants

that are located in

moderate to severe

weathering

conditions

(weathering index

> 100 day-inch/yr)

(NUREG-1557).

3-371
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

ItemNo.) __ _ _ _ _ _ _ __ _ _ _ _ _ _ __ _ _ _ _ _ _ __ _ _ _ _ _ _

Group 6: all Cracking due to Accessible areas: Structures Consistent with

accessible/ expansion/reaction Inspection of Monitoring Program GALL Report, which

inaccessible with aggregates Water-Control recommends further

reinforced concrete Structures or evaluation (See

(3.5.1-36) FERC/US Army SER

Corps of Engineers Section 3.5.2.2.2)

dam inspections

and maintenance

programs. None for

inaccessible areas

if concrete was

constructed in

accordance with

the

recommendations

in ACI 201.2R-77.

Group 6: exterior Increase in porosity For accessible None Consistent with

above and below and permeability, areas, Inspection of GALL Report, which

grade reinforced loss of strength due Water-Control recommends further

concrete foundation to leaching of Structures or evaluation (See interior slab calcium hydroxide FERC/US Army SER

(3.5.1-37) Corps of Engineers Section 3.5.2.2.2)

dam inspections

and maintenance

programs. None for

inaccessible areas

if concrete was

constructed in

accordance with

the

recommendations

in ACI201.2R-77.

Groups 7, 8: Tank Cracking due to A plant-specific Structures Consistent with

liners stress corrosion aging management Monitoring Program GALL Report, which

(3.5.1-38) cracking; loss of program is to be recommends further

material due to evaluated evaluation (See

pitting and crevice SER

corrosion Section 3.5.2.2.2)

Support members; Loss of material Structures Structures Consistent with

welds; bolted due to general and Monitoring Program Monitoring Program GALL Report, which

connections; pitting corrosion recommends further

support anchorage evaluation (See

to building structure SER

(3.5.1-39) _________ _________________Section 3.5.2.2.2)

3-372
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Building concrete at Reduction in Structures Structures Consistent with

locations of concrete anchor Monitoring Program Monitoring Program GALL Report, which

expansion and capacity due to recommends further

grouted anchors; local concrete evaluation (See

grout pads for degradation/ SER

support base plates service-induced Section 3.5.2.2.2)

(3.5.1-40) cracking or other

concrete aging

mechanisms

Vibration isolation Reddction or loss of Structures Structures Consistent with

elements isolation . Monitoring Program Monitoring Program. GALL Report, which

(3.5.1-41) function/radiation recommends further

hardening, evalkation (See

temperature, SER

humidity, sustained Section 3.5.2.2.2)

vibratory loading.

Groups B1.1, B1.2, Cumulative fatigue TLAA, evaluated in None Not applicable (See

and B1.3: support damage (CLB accordance with SER

members: anchor fatigue analysis 10 CFR 54.21(c) Section 3.5.2.2.2)

bolts, welds exists) (No CLB fatigue

(3.5.1-42) analysis exists)

Groups 1-3, 5, 6: all Cracking due to Masonry Wall Masonry Wall & Fire Consistent with

masonry block walls restraint shrinkage, Program Protection Programs GALL Report, which

(3.5.1-43) creep, and recommends no

aggressive further evaluation

environment (See SER

Section 3.5.2.1)

Group 6 elastomer Loss of sealing due Structures Consistent with

seals, gaskets, and to deterioration of Monitoring Program Structures GALL Report, which

moisture barriers seals, gaskets, and Monitoring Program recommends no

(3.5.1-44) moisture barriers further evaluation

(caulking, flashing, (See SER

and other sealants) Section 3.5.2.1)

Group 6: exterior Loss of material Inspection of Structures Consistent with

above and below due to abrasion, Water-Control Monitoring Program GALL Report, which

grade concrete cavitation Structures or recommends no

foundation; interior FERC/US Army further evaluation

slab Corps of Engineers (See SER

(3.5.1-45) dam inspections Section 3.5.2.1.5)

and maintenance

3-373
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Group 5: Fuel pool Cracking due to Water Chemistry Water Chemistry Consistent with

liners stress corrosion and monitoring of Control Program GALL Report, which

(3.5.1-46) cracking; loss of spent fuel pool recommends no

material due to water level in further evaluation

pitting and crevice accordance with (See SER

corrosion technical Section 3.5.2.1)

specifications and

leakage from the

leak chase

channels.

Group 6: all metal Loss of material Inspection of None Consistent with

structural members due to general Water-Control GALL Report, which

(3.5.1-47) (steel only), pitting Structures or recommends no

and crevice FERC/US Army further evaluation

corrosion Corps of Engineers (See SER

dam inspections Section 3.5.2.1)

and maintenance. If

protective coatings

are relied upon to

manage aging,

protective coating

monitoring and

maintenance

provisions should

be included.

Group 6: earthen Loss of material, Inspection of None Not applicable (See

water control loss of form due to Water-Control SER

structures - dams, erosion, settlement, Structures or Section 3.5.2.1.9)

embankments, sedimentation, frost FERC/US Army

reservoirs, action, waves, Corps of Engineers

channels, canals, currents, surface dam inspections

and ponds runoff, Seepage and maintenance

(3.5.1-48) programs

Support members; Loss of Water Chemistry Water Chemistry Consistent with

welds; bolted material/general, and ISl (IWF) and IWF Program GALL Report, which

connections; pitting, and crevice recommends no

support anchorage corrosion further evaluation

to building structure (See SER

(3.5.1-49) Section 3.5.2.1.7)

Groups B2, and B4: Loss of material Structures Structures Consistent with

galvanized steel, due to pitting and Monitoring Program Monitoring Program GALL Report, which

aluminum, stainless crevice corrosion recommends no

steel support further evaluation

members; welds; (See SER

bolted connections; Section 3.5.2.1)

support anchorage

to building structure

(3.5.1-50)

3-374
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Group B1.1: high Cracking due to Bolting Integrity None Aging effect not

strength low-alloy stress corrosion applicable (See

bolts cracking; loss of SER

(3.5.1-51) material due to Section 3.5.2.1.10)

general corrosion

Groups B2, and B4: Loss of mechanical Structures None Aging effect not

sliding support function due to Monitoring Program applicable (See

bearings and sliding corrosion, SER

support surfaces distortion, dirt, Section 3.5.2.1.10)

(3.5.1-52) overload, fatigue

- - due to vibratory and

cyclic thermal loads

Groups B1.1, B1.2, Loss of material ISI (IWF) IWF Program Consistent with

and B1.3: support due to general and GALL Report, which

members: welds; pitting corrosion recommends no

bolted connections; further evaluation

support anchorage (See SER

to building structure Section 3.5.2.1.8)

(3.5.1-53)

Groups B1.1, B1.2, Loss of mechanical ISI (IWF) None Aging effect not

and B1.3: Constant function due to applicable (See

and variable load corrosion, SER

spring hangers; distortion, dirt, Section 3.5.2.1.10)

guides; stops; overload, fatigue

(3.5.1-54) due to vibratory and

cyclic thermal loads

Steel, galvanized Loss of material Boric Acid None Not applicable to

steel, and aluminum due to boric acid Corrosion BWRs

support members; corrosion

welds; bolted

connections;

support anchorage

to building structure

(3.5.1-55)

Groups B1.1, B1.2, Loss of mechanical ISI (IWF) Structures Consistent with

and B1.3: Sliding function due to Monitoring Program GALL Report, which

surfaces corrosion, recommends no

(3.5.1-56) distortion, dirt, further evaluation

overload, fatigue (See SER

due to vibratory and Section 3.5.2.1)

cyclic thermal loads

Groups B1.1, B1.2, Reduction or loss of ISI (IWF) None Not applicable (See

and B1.3: Vibration isolation function/ SER

isolation elements radiation hardening, Section 3.5.2.1.9)

(3.5.1-57) temperature,

humidity, sustained

vibratory loading

3-375
Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

(GALL Report Mechanism Report

Item No.)

Galvanized steel None None None Consistent with

and aluminum GALL Report

support members;

welds; bolted

connections;

support anchorage

to building structure

exposed to air -

indoor uncontrolled

(3.5.1-58)

Stainless steel None None None Consistent with

support members; GALL Report

welds; bolted

connections;

support anchorage

to building structure

(3.5.1-59)

The staff's review of the structures and component supports component groups followed one of

several approaches. One approach, documented in SER Section 3.5.2.1, discusses the staff's

review of the AMR results for components that the applicant indicated are consistent with the

GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.5.2.2, discusses the staff's review of the AMR results for components that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.5.2.3, discusses the staff's

review of the AMR results for components that the applicant indicated are not consistent with,

or not addressed in, the GALL Report. The staffs review of AMPs that are 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 That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the structures and component supports

components:

" Containment Leak Rate Program

" Fire Protection Program

* Fire Water System Program

" Containment Inservice Inspection Program

" Inservice Inspection Program

* Masonry Wall Program

" Structures Monitoring Program

• Water Chemistry Control - BWR Program

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In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant provided a summary of AMRs for the

structures and component supports components and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report does not

recommend further evaluation, the staff performed an audit and review to determine whether

the plant-specific components contained in these GALL Report component groups were

bounded by the GALL Report evaluation.

-The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL' Report. The staff audited these line- items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In, addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPS had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant is consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the AMP identified by the GALL Report. This note indicates that the

applicant was unable to find a listing of some system components in the GALL Report;

however, the applicant identified a different component in the GALL Report that has the same

material, environment, aging effect, and AMP as the component that was under review. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the AMR line item of the different component was applicable to the

component under review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these

line items to verify consistency with the GALL Report. The staff verified whether the AMR line

item of the different component was applicable to the component under review. The staff

verified whether the identified exceptions to the GALL AMPS had been reviewed and accepted

by the staff. The staff also determined whether the AMP identified by the applicant was

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the

site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

3-377
items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified in the GALL

Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA and the bases

documents. The staff did not repeat its review of the matters described in the GALL Report;

however, the staff did verify that the material presented in the LRA was applicable and that the

applicant identified the appropriate GALL Report AMRs. The staff's evaluation is discussed

below.

For aging management evaluations that the applicant stated are consistent with the GALL

Report and for which further evaluation is not recommended, the staff conducted its audit and

review to determine if the-applicant's reference to the GALL Report in the LRA is acceptable.

The staff evaluated AMR line items to determine that the applicant (1) provides a brief

description of the system, components, materials, and environment; (2) states that the

applicable aging effects have been reviewed and are evaluated in the GALL Report; and (3)

identifies those aging effects for the reactor building, primary containment, water control

structures, turbine building complex and yard structures, and bulk commodities components

that are subject to an AMR. The staff also determined that the LRA line item is consistent with

the GALL Report Volume 2 system tables line item for component type and material,

environment, aging effects, and AMP.

3.5.2.1.1 Loss of Sealing and Leakage through Containment Due to Deterioration of Joint

Seals, Gaskets, and Moisture Barriers (Caulking, Flashing, and Other Sealants)

For loss of sealing and leakage through containment due to deterioration of elastomer, rubber,

and other similar material joint seals, gaskets, and moisture barriers (caulking, flashing, and

other sealants) exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends

programs consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE," and GALL

AMP XI.S4, "10 CFR Part 50, Appendix J." The applicant manages cracking and change in

material properties by the Containment Leak Rate Program and Structures Monitoring Program.

The LRA Table 2 AMR line items that reference this Table 1 line item cite Generic Note E,

indicating that the AMR line items are consistent with GALL Report material, environment, and

aging effect, but a different AMP is credited.

The staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-16, the applicant

stated that seals and gaskets are not included in the Containment Inservice Inspection

Program. One of the components for this item number is the floor moisture barriers.

During the audit and review, the staff asked whether the applicant uses the Containment

Inservice Inspection Program to manage the aging effect of the floor moisture barriers.

In its response, the applicant stated that the Structures Monitoring Program will manage the

aging effect of the drywell floor moisture barrier, and the Containment Leak Rate

(10 CFR Part 50, Appendix J) Program will manage the aging effect of the primary containment

electrical penetration seals and sealants. The staff noted that the drywell floor moisture barrier

is a containment internal seal, and therefore, 10 CFR Part 50, Appendix J does not apply and

the applicant's Structures Monitoring Program describe how it manages change in material

3-378
properties due to deterioration of the elastomer drywell floor liner seal (moisture barrier)

exposed to a protected-from-weather environment. Therefore, the staff finds it acceptable.

The staff reviewed the Structures Monitoring Program and its evaluation is documented in SER

Section 3.0.3.2.18. The Structures Monitoring Program encompasses the ASME Code

Section XI, Subsection IWE requirements for managing the deterioration (cracking and change

in material properties) of the primary containment moisture barrier through visual inspections.

The staff found it to be an acceptable management program for detecting cracking and change

in material properties.

But, cracking and change in material properties due to deterioration of the elastomer primary

containment. electrical penetration seals and sealant exposed-to a protected-from-weather

environment are managed using the Containment Leak Rate Program by the applicant.

The staff reviewed the Containment Leak Rate Program and its evaluation is documented in

SER Section 3.0.3.1.1. The applicant uses the Containment Leak Rate Program only to detect

deterioration of the containment electrical penetration seals and sealant. Although the GALL

Report also specifies GALL AMP XI.S1, "ASME Section XI, Subsection IWE," for this line item,

the 1998 Edition and later editions of the ASME Code Section XI, Subsection IWE, do not

require the inspection of seals and gaskets. Since the applicant has not assigned two AMPs to

manage this aging effect, the applicant has conservatively called the application of only the

Containment Leak Rate Program a different program with respect to the GALL Report.

Because the applicant's Containment Leak Rate Program is consistent with the GALL Report

and the 1998 Edition and later editions of the ASME Code Section XI, Subsection IWE, do not

require the inspection of seals and gaskets, the staff finds the Containment Leak Rate Program

alone to be an acceptable management program for detecting cracking and change in material

properties of containment electrical penetration seals and sealants.

On the basis of its review, the staff finds that the applicant appropriately addressed the AEM, as

recommended by the GALL Report.

3.5.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

In LRA Table 3.5.1, Item 3.5.1-18, the applicant stated that for loss of material due to general,

pitting and crevice corrosion of steel (and dissimilar metal welds) penetration sleeves,

personnel airlock, equipment hatch and CRD hatch exposed to indoor uncontrolled air or

outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME

Section XI, Subsection IWE," and GALL AMP XI.S4, "10 CFR Part 50, Appendix J." In the

discussion column for this line item, the applicant stated that Containment Inservice Inspection

(CII) and Containment Leak Rate Programs will manage this aging effect. The LRA Table 2

AMR line items that reference this Table 1 line item cite Generic Note E, indicating that the

AMR line items are consistent with GALL Report material, environment, and aging effect, but a

different AMP is credited.

However, loss of material of the carbon steel CRD removal hatch, equipment hatch, personnel

airlock, primary containment electrical penetrations, torus electrical penetrations, and torus

mechanical penetrations exposed to a protected-from-weather environment is managed using

the Containment Inservice Inspection Program (plant-specific) and the Containment Leak Rate

3-379
Program by the applicant.

The staff reviewed the Containment Inservice Inspection Program and its evaluation is

documented in SER Section 3.0.3.3.2. The Containment Inservice Inspection Program

encompasses the ASME Code Section XI, Subsection IWE requirements for managing the loss

of material for the primary containment and its integral attachments.

Because the applicant's plant-specific Containment Inservice Inspection Program includes the

same requirements for inspection and detection of loss of material for the primary containment

and its integral attachments as the ASME Code Section XI, Subsection IWE, the staff finds it to

be an acceptable management program for loss of material of the above components.

The staff also reviewed the Containment Leak Rate Program and its evaluation is documented

in SER Section 3.0.3.1.1. The applicant's Containment Leak Rate Program is consistent with

GALL AMP XI.S4. The staff finds the Containment Leak Rate Program to be an acceptable

AMP to detect loss of material of the carbon steel CRD removal hatch, equipment hatch,

personnel air lock, primary containment electrical penetrations, torus electrical and mechanical

penetrations.

On the basis of its review, the staff finds that the applicant appropriately addressed the AEM, as

recommended by the GALL Report.

3.5.2.1.3 Loss of Material Due to General and Pitting Corrosion

In LRA Table 3.5.1, Item 3.5.1-39, the applicant stated that for loss of material due to general,

pitting, and corrosion of steel support members, welds, bolted connections, and support

anchorage to building structures exposed to indoor uncontrolled air or outdoor air, the GALL

Report recommends programs consistent with GALL AMP XI.S6, "Structures Monitoring

Program." In the discussion column for this line item, the applicant stated that loss of material of

carbon steel fire hose reels and damper framing exposed to a protected-from-weather

environment is managed using the Fire Protection Program or Fire Water System Program.

The LRA Table 2 AMR line items that reference this Table 1 line item cite Generic Note E,

indicating that the AMR line items are consistent with GALL Report material, environment, and

aging effect, but a different AMP is credited. The staffs further evaluation of Group 1-5, 7, and

8 Structures is discussed in SER Section 3.5.2.2.2 for this line item.

The staff reviewed the Fire Water System Program and its evaluation is documented in SER

Section 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection

systems which consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations (including

fire hose reels), standpipe, and aboveground and underground piping and components.

Components are tested in accordance with applicable NFPA codes and standards. Such testing

assures that carbon steel fire hose reels and damper housing will be inspected for corrosion.

Because the applicant's Fire Water System Program includes hose stations (including fire hose

reels) which are tested in accordance with NFPA codes and standards to detect corrosion, the

staff found it to be an acceptable management program for loss of material of fire hose reels in

lieu of the Structures Monitoring Program.

The staff reviewed the Fire Protection Program and its evaluation is documented in SER

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Section 3.0.3.2.11. The program is enhanced to require visual inspection of components when

the diesel driven fire pump is running to verify no degradation is occurring.

On the basis of its review, the staff finds the applicant appropriately addressed loss of material

due to general, pitting, and corrosion of steel support members, welds, bolted connections, and

support anchorage to building structures exposed to indoor uncontrolled air or outdoor air.

3.5.2.1.4 Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers

(Caulking, Flashing, and Other Sealants)

The staff noted that in LRA Table 3.5.2-4, the applicant stated that for component seals and

gaskets (doors, manway, and hatches), rubber material is protected from weather environment;

the aging effects are cracking -and change in material properties. The AERM is identified as

"Structures Monitoring Program." The GALL Report line item referenced is III.A6-12, and the

Table 1 reference is 3.5.1-44. The LRA Table 2 AMR line items that reference this Table 1 line

item cite Generic Note E, indicating that the AMR line items are consistent with GALL Report

material, environment, and aging effect, but a different AMP is credited. However, the staff

noted that GALL Report Item III.A6-12 and Table 1 Item 3.5.1-44 both specify the Structures

Monitoring Program.

During the audit and review, the staff asked the applicant to explain why the line items were

assigned Note E instead of Note A for the lower half of this AMR line items.

The applicant stated that the LRA Table 3.5.2-4 for line item 3.5.1-44 will be clarified to indicate

that Note A applies to this item. In its response dated February 1, 2007, the applicant revised

LRA Table 3-5.2-4 to state "structure and/or component or commodity of seals and gaskets,

Note "A" replaces Note "E."

The staff reviewed the Structures Monitoring Program and its evaluation is documented in SER

Section 3.0.3.2.18. The staff determined that the applicant's program is consistent with GALL

Report with enhancements. The program will be enhanced to provide guidance for performing

structural examinations of elastomers (seal, gasket, seismic joint filler, and roof elastomers) to

identify cracking and change in material properties.

On the basis of its review of the applicant's response, the staff finds the response acceptable

and that the applicant appropriately addressed the AEM, as recommended by the GALL Report.

3.5.2.1.5 Loss of Material Due to Abrasion, Cavitation

In LRA Table 3.5.1, Item 3.5.1-45, the applicant stated that for loss of material due to abrasion

and cavitation of reinforced concrete exterior above and below grade foundation and interior

slab exposed to flowing water, the GALL Report recommends programs consistent with GALL

AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants."

However, in the discussion column for this line item, the applicant stated that loss of material of

reinforced concrete exterior walls below grade (SW area), exterior walls below grade (CWS

area), foundation, interior walls below grade, exterior walls above grade, exterior walls below

grade, and foundation exposed to a fluid environment, is managed using the Structures

3-381
Monitoring Program. The LRA Table 2 AMR line items that reference this Table 1 line item cite

Generic Note E, indicating that the AMR line items are consistent with GALL Report material,

environment, and aging effect, but a different AMP is credited.

The staff reviewed the Structures Monitoring Program and its evaluation is documented in SER

Section 3.0.3.2.18. The staff determined that the attributes of GALL AMP XI.S7, "Regulatory

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants,"

applicable to the water control structures have been incorporated into the applicant's Structures

Monitoring Program. On this basis, the staff found the Structures Monitoring Program to be an

acceptable AMP for loss of material of the components listed above.

On the basis of its review, the staff finds the applicant appropriately addressed the AERM, as

recommended, by the GALL Report.

3.5.2.1.6 Loss of Material Due to General (Steel Only), Pitting, and Crevice Corrosion

In LRA Table 3.5.1, Item 3.5.1-47, the applicant stated that:

For loss of material due to general, pitting, and crevice corrosion of group six

metal structural members exposed to indoor uncontrolled air, outdoor air, flowing

water, or standing water, the GALL Report recommends programs consistent

with GALL AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control

Structures Associated with Nuclear Power Plants."

However, in the discussion column for this line item, the applicant stated that loss of material of

metal structural steel beams, columns, plates exposed to a protected-from-weather-or-fluid

environment; metal anchorage/embedment exposed to a fluid environment; metal manway

hatches and hatch covers exposed to a protected-from-weather or weather environment; and

structural bolting exposed to a fluid environment, is managed using the Structures Monitoring

Program. The LRA Table 2 AMR line items that reference this Table 1 line item cite Generic

Note E, indicating that the AMR line items are consistent with GALL Report material,

environment, and aging effect, but a different AMP is credited.

The staff reviewed the Structures Monitoring Program and its evaluation is documented in SER

Section 3.0.3.2.18. GALL AMP XI.S7 states that for plants not committed to RG 1.127,

Revision 1, aging management of water control structures may be included in the Structures

Monitoring Program. The attributes of GALL AMP XI.S7, "Regulatory Guide 1.127, Inspection of

Water-Control Structures Associated with Nuclear Power Plants," applicable to the water control

structures have been incorporated into the applicant's Structures Monitoring Program.

Because the applicant's Structures Monitoring Program includes the attributes of GALL

AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants," applicable to the water control structures as recommended by the GALL

Report, the staff found it to be an acceptable management program for loss of material of the

components listed above.

On the basis of its review, the staff found the applicant appropriately addressed the AEM, as

recommended by the GALL Report.

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3.5.2.1.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

In LRA Table 3.5.1, Item 3.5.1-49, the applicant stated:

For loss of material due to general, pitting, and crevice corrosion of stainless

steel and steel support members; bolted connections; support anchorage to

building structure exposed to treated water (<1400 F) the GALL Report

recommends programs consistent with GALL AMP XI.M2, "Water Chemistry," for

BWR water, and GALL AMP XI.S3, "ASME Section XI, Subsection IWF."

However, in the discussion column for this line item, the applicant stated that loss of material of

carbon steel and stainless steel (SS) anchorage/embedments exposed to a fluid environment is

managed using the Water Chemistry Control.- BWR Program and the Inservice Inspection

Program. The LRA Table 2 AMR line items that reference this Table 1 line item cite Generic

Note E, indicating that the AMR is consistent with GALL Report material, environment, and

aging effect, but a different AMP is credited.

The staff reviewed the Water Chemistry Control - BWR Program and its evaluation is

documented in SER Section 3.0.3.1.10. The JAFNPP Water Chemistry Control - BWR Program

is based on BWRVIP-1 30 guidelines and it provides an acceptable method of controlling water

chemistry that is consistent with the GALL Report recommendations for managing the loss of

material for ASME Class 1, 2, and 3 steel piping supports and steel component supports within

containment.

Because the applicant's Water Chemistry Control - BWR Program includes the attributes of

GALL AMP XI.M2, "Water Chemistry," applicable to the Water Chemistry Control - BWR as

recommended by the GALL Report, the staff found it to be an acceptable program for

managing the loss of material for ASME Class 1, 2, and 3 steel piping supports and steel

component supports within containment.

The staff reviewed the Inservice Inspection Program and its evaluation is documented in SER

Section 3.0.3.3.3. The JAFNPP Inservice Inspection Program encompasses the ASME Code

Section XI, Subsection IWF requirements for managing the loss of material for ASME Class 1,

2, and 3 steel piping supports and steel component supports within containment.

Because the applicant's plant-specific Inservice Inspection Program includes the same

requirements for inspection and detection of loss of material for ASME Class 1, 2, and 3 steel

piping supports and steel component supports within containment as the ASME Code

Section XI, Subsection IWF, the staff found it to be an acceptable management program for

loss of material of carbon steel and SS anchorage/embedment.

On the basis of its review, the staff found the applicant appropriately addressed the AEM, as

recommended by the GALL Report.

3.5.2.1.8 Loss of Material Due to General and Pitting Corrosion

In the discussion column of LRA Table 3.5.1, Item 3.5.1-53, the applicant stated that loss of

material due to general and pitting corrosion of steel support members; welds, bolted

connections; and support anchorage to building structure exposed to indoor uncontrolled air or

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outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S3, "ASME

Section Xl, Subsection IWF."

However, loss of material of steel RV support assembly, RV stabilizer supports, torus external

supports (columns, saddles), anchorage/embedment, base plates, component and piping

supports ASME Class 1, 2, 3 and MC, anchor bolts, and ASME Class 1, 2, 3 and MC supports

bolting exposed to a protected-from-weather environment and anchorage/embedment, base

plates, component and piping supports ASME Class 1, 2, 3 and MC, anchor bolts, and ASME

Class 1, 2, 3 and MC supports bolting exposed to a weather environment is managed using the

Inservice Inspection Program by the applicant.

The staff reviewed the Inservice Inspection Program and its evaluation is documented in SER

Section 3.0.3.3.3. The JAFNPP Inservice Inspection Program encompasses the ASME Code

Section XI, Subsection IWF requirements for managing the loss of material for ASME Class 1,

2, and 3 steel piping supports and steel component supports within containment.

Because the applicant's plant-specific Inservice Inspection Program includes the same

requirements for inspection and detection of loss of material for ASME Class 1, 2, and 3 steel

piping supports and steel component supports within containment as the ASME Code

Section XI, Subsection IWF, the staff found it to be an acceptable program for loss of material

of the components listed above.

On the basis of its review, the staff found that the applicant adequately addressed the AEM, as

recommended by the GALL Report.

3.5.2.1.9 AMR Results Identified as Not Applicable

In LRA Table 3.5.1, line items 19, 20, 22, 48, and 57 are identified as "Not Applicable" since the

component/material/ environment combination does not exist at JAFNPP. For each of these line

items, the staff reviewed the LRA and the applicant's supporting documents, and confirmed the

applicant's claim that the component/material/environment combination does not exist at

JAFNPP. On the basis that JAFNPP does not have the component/material/ environment

combination for these Table 1 line items, the staff finds that these AMRs are not applicable to

JAFNPP.

3.5.2.1.10 AMR Results with No Aging Effects Identified

In the LRA Table 3.5.1, item 3.5.1-51 discussion column, the applicant states that cracking and

loss of material of Group B1.1 - high-strength, low-alloy bolts - due to stress corrosion and

general corrosion is not applicable to JAFNPP. SCC of high-strength anchor bolts is not an

AERM at JAFNPP for two reasons: (1) JAFNPP does not utilize high-strength bolting in

structural applications; the bolting used is not exposed to a corrosive environment or high

tensile stresses; and (2) bolting connections are installed with friction-type contact surfaces via

the turn-of-the-nut method; therefore, for bolts greater than 1 inch in diameter, a significant

preload (in the order of 70 percent of ultimate strength) is not practical to develop. The JAFNPP

Inservice Inspection (IWF) Program manages loss for bolting connections.

The staff finds acceptable the applicant's assessment that cracking of high-strength low-alloy

bolts due to stress corrosion will not occur for Group B1.1 components since a corrosive

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environment and high tensile stresses do not exist.

On the basis that the environment and high tensile stresses needed to cause cracking from

SCC do not exist for high-strength low-alloy bolts in the SC supports at JAFNPP, the staff finds

that, for this component type, this aging effect is not applicable to JAFNPP.

In the LRA Table 3.5.1, item 3.5.1-52 discussion column, the applicant states that the loss of

mechanical function of Groups B2 and B4 - sliding support bearing and sliding support

surfaces due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic

thermal loads - is not applicable to JAFNPP as discussed below.

In the discussion section of LRA Table 3.5.1, item 3.5.1752, the applicant states that loss of

mechanical function due to the listed mechanisms is not an aging effect. Such failures typically

result from inadequate design or operating events rather than from the effects of aging.

Failures due to cyclic thermal loads are rare for structural supports due to their relatively low

temperatures.

The applicant stated that the sliding surface material used at JAFNPP is Lubrite®, which is a

corrosion-resistant material. Components are inspected under the Inservice Inspection (IWF)

Program for torus saddle supports and Structures Monitoring Program for the Lubrite®

components of radial beam seats. Plant operating experience has not identified failure of

Lubrite® components used in structural applications. No current industry experience has

identified failure associated with Lubrite® sliding surfaces. Components associated with B2

grouping are limited to the torus radial beam seats and support saddles. There are no sliding

support surfaces associated with the B4 component grouping for sliding surfaces at JAFNPP.

The staff finds acceptable the applicant's assessment that loss of mechanical function due to

distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads are not AERMs.

Such failures do typically result from inadequate design or events rather than the effects of

aging.

On the basis that the mechanisms provided in LRA Table 3.5.1, item 3.5.1-52, other than

corrosion, are not aging mechanisms which cause aging effects for Groups B2 and B4

components in the SC supports at JAFNPP, the staff finds that, for this component type, this

aging effect is not applicable to JAFNPP.

In the LRA Table 3.5.1, item 3.5.1-54 discussion column, the applicant states that the loss of

mechanical function of Groups B1.1, B1.2, and B1.3 - constant and variable load spring

hangers; guides and stops due to corrosion, distortion, dirt, overload, fatigue due to vibratory

and cyclic thermal loads - is not applicable to JAFNPP as discussed below.

In the discussion section of LRA Table 3.5.1, item 3.5.1-54, the applicant states that loss of

mechanical function due to the listed mechanisms is not an aging effect. Loss of mechanical

function due to distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads are not

AERMs. Such failures typically result from inadequate design or events rather than the effects

of aging. Loss of material due to corrosion, which could cause loss of mechanical function, is

addressed under Item 3.5.1-53 for Groups B1.1, B1.2, and 81.3 support members.

The staff finds acceptable the applicant's assessment that loss of mechanical function due to

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corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads are not

AERMs. Such failures do typically result from inadequate design or events rather than the

effects of aging.

On the basis that the mechanisms provided in LRA Table 3.5.1, item 3.5.1-54, other than

corrosion, are not aging mechanisms which cause aging effects for Groups B1.1, B1.2, and

B13.3 components in the SC supports at JAFNPP, the staff finds that, for this component type,

this aging effect is not applicable to JAFNPP.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing the associated aging effects. On the basis of its review,

the staff concludes that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are indeed consistent with the AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for

the structures and component supports components. The applicant provided information

concerning how it will manage aging effects in the following three areas:

(1) PWR and BWR containments:

" aging of inaccessible concrete areas

• cracks and distortion due to increased stress levels from settlement; reduction of

foundation strength, cracking and differential settlement due to erosion of porous

concrete subfoundations, if not covered by structures monitoring program

" reduction of strength and modulus of concrete structures due to elevated

temperature

" loss of material due to general, pitting and crevice corrosion

" loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

" cumulative fatigue damage

" cracking due to stress corrosion cracking

" cracking due to cyclic loading

* loss of material (scaling, cracking, and spalling) due to freeze-thaw

" cracking due to expansion and reaction with aggregate, and increase in porosity

and permeability due to leaching of calcium hydroxide

(2) safety-related and other structures and component supports:

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" aging of structures not covered by structures monitoring program

" aging management of inaccessible areas

" reduction of strength and modulus of concrete structures due to elevated

temperature

" aging management of inaccessible areas for Group 6 structures

* cracking due to stress corrosion cracking and loss of material due to pitting and

crevice corrosion

" aging of supports not covered by structures monitoring program

* cumulative fatigue damage due to cyclic loading

(3) QA for aging management of nonsafety-related components

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The

staff's evaluation of the aging effects is discussed in the following sections.

3.5.2.2.1 PWR and BWR Containments

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1,

which addresses several areas that are discussed below.

Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the

criteria in SRP-LR Section 3.5.2.2.1.1.

In LRA Section 3.5.2.2.1.1, the applicant states that JAFNPP has a Mark I free-standing steel

containment located within the reactor building. Inaccessible and accessible concrete areas are

designed in accordance with ACI specification ACI 318-63, "Building Code Requirements for

Reinforced Concrete," which results in low permeability and resistance to aggressive chemical

solutions by requiring the following:

" high cement content

" low water-to-cement ratio

" proper curing

" adequate air entrainment

JAFNPP concrete also meets requirements of later ACI guide ACI 201.2R-77, "Guide to

Durable Concrete," since both documents use the same ASTM standards for selection,

application, and testing of concrete.

The below-grade environment is not aggressive (pH > 5.5, chlorides < 500 ppm, and sulfates <

1500 ppm). Concrete was provided with at least the minimum required air content between 3

and 6percent and a low water/cement ratio (0.50 or less). Although specified water/cement

ratios fall outside the established range of 0.35 to 0.45, given all remaining parameters for

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durable concrete mix design, JAFNPP concrete meets the quality requirements of ACl to

ensure acceptable concrete is obtained. Therefore, increase in porosity and permeability,

cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not

applicable to concrete in inaccessible areas. The absence of concrete aging effects is

confirmed under the Structures Monitoring Program.

SRP-LR Section 3.5.2.2.1.1 states that increases in porosity and permeability, cracking, loss of

material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and

loss of material (spalling, scaling) due to corrosion of embedded steel could occur in

inaccessible areas of PWR and BWR concrete and steel containments. The existing program

relies on ASME Section XI, Subsection IWL to manage these aging effects. However, the GALL

Report recommends further evaluation of plant-specific programs to manage the aging effects

for inaccessible areas if the environment is aggressive.

The staff found these aging effects not applicable to the Mark I freestanding steel containment.

The listed possible aging effects apply to concrete elements of PWR containments and

concrete BWR containments. The Mark I steel containment is located within the concrete

reactor building, and the applicant statement is for that concrete structure.

On the basis that there are no components from this group, the staff concludes that this aging

effect is not applicable to JAFNPP.

Cracks and Distortion Due to Increased Stress Levels from Settlement: Reduction of

Foundation Strength, Cracking and Differential Settlement Due to Erosion of Porous Concrete

Subfoundations, If Not Covered by Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2.

The LRA Section 3.5.2.2.1.2 states that for the cracks and distortion due to increased stress

levels from settlement, reduction of foundation strength, cracking, and differential settlement

due to erosion of porous concrete subfoundations ( if not covered by the Structures Monitoring

Program), JAFNPP does not rely on a dewatering system for control of settlement. Structures

are founded on sandstone bedrock. JAFNPP containment was not identified in information

notice (IN) 97-11 as a plant susceptible to erosion of porous concrete subfoundations. JAFNPP

groundwater is not aggressive and there is no indication that ground water chemistry has

significantly changed and no changes in groundwater conditions have been observed.

As a result, cracking and distortion due to increased stress level from settlement and reduction

of foundation strength cracking and differential settlement due to erosion of porous concrete

subfoundation are not AERMs for JAFNPP concrete structures.

SRP-LR Section 3.5.2.2.1.2 states that cracks and distortion due to increased stress levels

from settlement could occur in PWR and BWR concrete and steel containments. Also,

reduction of foundation strength, cracking, and differential settlement due to erosion of porous

concrete subfoundations could occur in all types of PWR and BWR containments. The existing

program relies on structures monitoring program to manage these aging effects. Some plants

may rely on a de-watering system to lower the site ground water level. If the plant's CLB credits

a de-watering system, the GALL Report recommends verification of the continued functionality

of the de-watering system during the period of extended operation. The GALL Report

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recommends no further evaluation if this activity is within the scope of the applicant's structures

monitoring program.

The staff determined through discussions with the applicant's technical staff that the cracking

and distortion due to increased stress levels from settlement; reduction of foundation strength,

cracking, and differential settlement due to erosion of porous concrete subfoundations (if not

covered by the Structures Monitoring Program) are not plausible aging effects due to the

nonexistence of these aging mechanisms. The applicant states that the aging effects due to

settlement are not expected at JAFNPP for the Mark I steel containment since it is located

within the reactor building and supported by the reactor building foundation. The reactor

building is founded on sound bedrock which prevents significant settlement. In addition, there is

no porous concrete subfoundation below the reactor building of concern. The staff finds

acceptable the applicant's assessment that these aging effects are not applicable to the

JAFNPP containment due to the nonexistence of aging mechanisms.

The staff determined that these aging effects are not applicable to the JAFNPP containment.

On the basis that JAFNPP has no components from this group, the staff concludes that this

aging effect is not applicable.

Reduction of Strenqth and Modulus of Concrete Structures Due to Elevated Temperature. The

staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.

LRA Section 3.5.2.2.1.3 states that the aging effect of reduction of strength and modulus of

concrete structures due to elevated temperature is not applicable to JAFNPP. GALL Report

Volume 2 items referencing this issue are associated with concrete containments. JAFNPP is a

mark I steel containment.

SRP-LR Section 3.5.2.2.1.3 states that reduction of strength and modulus of concrete due to

elevated temperatures could occur in PWR and BWR concrete and steel containments. The

implementation of 10 CFR 50.55a and ASME Section XI, Subsection IWL would not be able to

identify the reduction of strength and modulus of concrete due to elevated temperature.

Subsection CC-3400 of ASME Section III, Division 2, specifies the concrete temperature limits

for normal operation or any other long-term period. The GALL Report recommends further

evaluation of a plant-specific AMP if any portion of the concrete containment components

exceeds specified temperature limits (i.e., general area temperature greater than 60 'C (150 °F)

and local area temperature greater than 93 °C (200 OF)).

The staff determined through discussions with the applicant's technical staff and review of

design bases documents that the reduction of strength and modulus for concrete structures due

to elevated temperature are not plausible aging effects due to the nonexistence of these aging

mechanisms. The applicant states that the aging effects due to elevated temperature are not

expected at JAFNPP for the concrete associated with the Mark I steel containment, since

general areas temperatures within the primary containment do not exceed 150 OF and local

area temperatures do not exceed 200°F. The staff finds acceptable the applicant's assessment

that these aging effects are not applicable to the JAFNPP containment since general areas

temperatures within the primary containment do not exceed 150 OF and local area temperatures

do not exceed 200 OF.

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On the basis that there are no components from this group, the staff concludes that this aging

effect is not applicable.

Loss of Material Due to General, Pitting and Crevice Corrosion. The staff reviewed LRA

Section 3.5.2.2.1.4 against the criteria of SRP-LR Section 3.5.2.2.1.4.

LRA Section 3.5.2.2.1.4 states that the Mark I steel containment is located within the reactor

building. Design of JAFNPP reactor building concrete in contact with the drywell shell is in

accordance with specification ACI 318-63, "Building Code Requirements for Reinforced

Concrete." The concrete meets requirements of later guide ACI 201.2R-77 as both documents

use the same ASTM standards for concrete selection, application, and testing. The Structures

Monitoring Program monitors concrete for cracks. The Containment Inservice Inspection (IWE)

Program and the Structures Monitoring Program inspect the drywell steel shell and the moisture

barrier where the drywell shell becomes embedded in the drywell concrete floor.

The LRA states that, to prevent corrosion of the lower part of the drywell shell, a complete

concrete encasement protects the interior and exterior surfaces from contact with the

atmosphere. Ground water cannot reach the drywell shell, assuming a crack in the concrete,

because at this location the concrete is more than eight feet thick and poured in multiple

horizontal planes. Drainage of the sand cushion area protects the exterior surface of the drywell

shell in contact with the sand cushion from entry of water into the air gap; therefore, significant

corrosion of the drywell shell is improbable.

SRP-LR Section 3.5.2.2.1.4 states that loss of material due to general, pitting, and crevice

corrosion could occur in steel elements of accessible and inaccessible areas of all types of

PWR and BWR containments. The existing program complies with ASME Section Xl,

Subsection IWE, and 10 CFR Part 50, Appendix J, in managing this aging effect. The GALL

Report recommends further evaluation of plant-specific programs to manage this aging effect

for inaccessible areas if corrosion is significant.

For loss of material due to general, pitting, and crevice corrosion of carbon steel in the drywell,

torus, drywell head, embedded shell and sand pocket regions, drywell support skirt, torus ring

girder, downcomers, liner plate, ECCS suction header, support skirt, region shielded by

diaphragm floor, and suppression chamber exposed to indoor uncontrolled air or treated water,

the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Section XI,

Subsection IWE," and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."

However, the applicant's Containment Inservice Inspection Program and Containment Leak

Rate Program manage loss of carbon steel material (LRA Table 3.5.1, page 3.5-20,

item 3.5.1-5) in the drywell head, drywell shell, drywell sump liner, drywell to torus vent system,

torus manway, torus ring girder, torus shell, and torus thermowell exposed to environments

protected from weather.

SER Section 3.0.3.3.2 documents the staff's evaluation of the Containment Inservice Inspection

Program, which encompasses ASME Code Section XI, Subsection IWE requirements for

managing the loss of material for the primary containment and its attachments. This program

and the Containment Leak Rate Program also manage loss of material of the carbon steel

drywell sump liner, torus ring girder, and torus shell exposed to a fluid environment. Because

the applicant's plant-specific Containment Inservice Inspection Program includes the same

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requirements for inspection and detection of loss of material for the primary containment and its

attachments as ASME Code Section XI, Subsection IWE, the staff found the AMP acceptable

for managing loss of material for such components.

The staff's review of LRA Section 3.5.2.2.1.4 identified areas in which additional information

was necessary to complete the review of the applicant's AMR results. The applicant responded

to the staff's RAIs as discussed below.

In RAI 3.5.2-1 dated January 12, 2007, the staff requested that the applicant verify that the

Containment Inservice Inspection Program and Containment Leak Rate Program manage

aging effects in both accessible and inaccessible areas.

In its response dated February 12, 2007, the applicant stated that, as LRA Table 3.5.2-1 shows,

the Containment Inservice Inspection (CII) Program and the Containment Leak Rate Program

manage loss of material for the drywell shell, drywell to torus vent system, and torus shell.

These programs manage the effects of aging in inaccessible areas when they become

accessible, when inspection results of similar component show significant degradation, or when

operating experience warrants such inspections. As LRA Section B.16.1 states, the

Containment Inservice Inspection (ClI) Program cites 10 CFR 50.55a(b)(2)(ix), which specifies

that licensees must evaluate the acceptability of inaccessible areas when conditions in

accessible areas could indicate or result in degradation in such inaccessible areas. As

LRA Section B.1.8 states, the Containment Leak Rate Program uses the 10 CFR Part 50,

Appendix J program described in GALL Report Section XI.S4. This program monitors leakage

rates through containment shells, containment liners, and welds, penetrations, fittings, and

other access openings and addresses leakage through inaccessible areas like the embedded

containment or drywell shell.

The staff finds the response to RAI 3.5.2-1 acceptable because the applicant's programs

adequately manage the aging of accessible and inaccessible areas of the containment.

Therefore, the staff's concern described in RAI 3.5.2-1 is resolved.

LRA Table 3.5.2-1 under Structure and/or Component or Commodity for "drywell shell" and

"torus shell," credits the Containment Inservice Inspection Program to manage the loss of

material due to general pitting and crevice corrosion. AMP operating experience states,

"Results of the CII general visual walkdown of primary containment during RO15 (2002)

revealed minor areas of peeling paint and rust scale."

In RAI 3.5.2-2 dated January 12, 2007, the staff requested from the applicant the root cause

and any preventive actions to alleviate the peeling paint and rust scale in primary containment.

In its response dated February 12, 2007, the applicant stated that during the 2002, 2004

and 2006 ROs a general visual walkdown of the primary containment for IWE for the various

elevations from 256'-6" to 331'-0" revealed minor surface areas with cracking or peeling paint,

rust scale, or both. In 2002, CR-JAF-2003-02527 reported the degraded conditions and work

order JF-030619900 completed maintenance activities. The apparent causes of the cracking or

peeling paint is improper cleaning and preparation of the steel substrate and coating

delaminating from the surface. Areas of concern have minor surface degradations that have

been repaired. JAFNPP will continue general visual walkdowns of primary containment during

ROs in accordance with the IWE. The Corrective Action Program will evaluate any degraded

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conditions for appropriate repair as required.

The staff finds the applicant's response to RAI 3.5.2-2 acceptable. The staff finds the

applicant's programs for managing the aging of drywell and torus shell acceptable because

proper implementation of the programs during outages will ensure the integrity of these

components in the period of extended operation. Therefore, the staff's concern described in

RAI 3.5.2-2 is resolved.

LRA Table 3.5.2-1 under Structure and/or Component or Commodity for "drywell shell," credits

the Containment Inservice Inspection Program and the Containment Leak Rate Program to

manage the loss of material due to general pitting and crevice corrosion; however, it was

unclear to the staff how and when inspections verified whether observed leakage caused

moisture in the vicinity of the sand cushion and whether moisture detected or suspected on the

inaccessible areas of the drywell shell would cause corrosion and wall thinning.

In RAI 3.5.2-3 dated January 12, 2007, the staff requested that the applicant address proposed

license renewal interim staff guidance LR-ISG-2006-01, "Plant Specific Aging Management

Program for Inaccessible Areas of Boiling Water Reactor Mark 1 Steel Containment Drywell

Shell," published in the Federal Register on May 9, 2006. The staff also requested from the

applicant significant findings during the implementation of GL 87-05, "Request for Additional

Information-Assessment of Licensee Measures to Mitigate And/Or Identify Potential

Degradation of Mark I Drywells," and subsequent examinations.

The applicant's response dated February 12, 2007, provided details of how the NRC generic

communication relates to potential corrosion of the Mark I steel containment and additional

information on recent industry experience and the drywell shell. The response described the

purpose, background, primary containment design, drywell shell exterior, drywell shell interior,

operating experience, and actions to prevent drywell corrosion.

The applicant stated the following for plant-specific operating experience and the actions to

prevent drywell corrosion:

The sand cushion area at the base of the drywell is drained to protect the

exterior surface of the drywell shell at the sand cushion interface from water that

might enter the air gap. To ensure the drywell shell exterior remains dry during

refueling outages, the drywell to reactor building bellows assembly separates the

refueling cavity filled with water from the exterior surface of the drywell shell. Any

leakage through the bellows assembly is directed to a drain system which is

equipped with an alarm for notification of operators. Functional checks are

performed on the alarm system and the air gap drains are monitored twice every

refuel outage, once after flood-up and again prior to flood-down at the end of the

outage. JAFNPP inspects the liner drains for the water reservoirs on the refuel

floor (e.g., spent fuel pool, dryer/separator pool, and the reactor cavity) for

leakage. Leakage into the liner drains could be a precursor for water leaks which

could wet the drywell shell exterior surface. These-drains are examined for

leakage after filling the refueling cavity.

To ensure the drywell shell exterior remains dry during refueling outages, the

drywell to reactor building bellows assembly separates the refueling cavity filled

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with water from the exterior surface of the drywell shell. A backing plate

surrounds the outer circumference of the bellows to protect it and provide a

mechanism for testing and monitoring of leakage. Any leakage through the

bellows assembly is directed to a drain system which is equipped with an alarm

for notification of operators.

To ensure the drywell shell exterior remains dry during refueling outages, the

drywell to reactor building bellows assembly separates the refueling cavity filled

with water from the exterior surface of the drywell shell. Any leakage through the

bellows assembly is directed to a drain system ((inner bellows to the Drywell

Equipment Drain Sump, outer bellows to the "B" Condensate Storage Tank),

where two lines are each equipped with a flow indicator/switch that will alarm in

the Control Room in the event of a bellows failure. A preventive maintenance

(PM) - "Test of 19FIS-61 prior to initial refuel cavity flood-up" is performed every

outage to verify the indicator/switch is functional and the Control Room

annunciator responds when water is added to the line. In addition, a PM -

"Functional Test of 19FIS-62" is performed every two years to verify the

indicator/switch and associated Control Room annunciator are functional. If

moisture/leakage is detected in the inaccessible area on the exterior of the

drywell shell JAFNPP will: (a) identify the component source which may have

introduced the moisture/leakage and include the component in an AMR program,

(b) identify the surface areas requiring examination and implement augmented

inspections for the period of extended operation in accordance with the American

Society of mechanical Engineers (ASME) Section XI, Subsection IWE-1 240 as

identified in table IWE-2500-1, Examination category E-C, and (c) demonstrate

through use of augmented inspections performed in accordance with ASME

Code Section XI, Subsection IWE that corrosion is not occurring, or that

corrosion is progressing so slowly that the age-related degradation will not

jeopardize the intended function of the drywell shell through the period of

extended operation.

There has been no observed active leakage causing moisture in the vicinity of

the sand cushion drain line at JAFNPP as monitored by IWE general visual

examination of the exterior of the torus and torus room. No moisture has been

detected or suspected on the inaccessible areas of the drywell shell. Any

leakage through the refueling bellows assembly is directed to a drain system

(inner bellows to the Drywell Equipment Drain Sump, outer bellows to the "B"

Condensate Storage Tank). Therefore, no additional components have been

identified that require an AMR as a source of moisture that may affect the drywell

shell in the lower region.

In 1988, the applicant examined the air gap through the drain lines using

fiber optic cables and did not have any evidence of moisture potentially

causing corrosion of the drywell shell (Reference NYPA Memorandum

No. JTS-88-0875, from V. Walz to W. Fernandez, dated November 1,

1988). The applicant plans to perform an additional examination in 2007.

If any evidence of moisture is identified, JAF will determine additional

inspection activities, as appropriate.

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JAF monitors refueling bellows leakage drain lines during every refueling

outage. Flow indicator/switches 19FIS-61 and 19FIS-62 were

successfully last tested in 2006. The flow indicators/switches are on a two

year PM frequency.

Drywell interior surfaces are examined for degradation every refueling

outage in accordance with the JAF IWE Program. A general visual

examination has been performed every refueling outage looking at the

steel and concrete surfaces for shrinkage cracks in the concrete,

cracking and peeling coating, and discoloration of the surface coating

(bleed through, staining). There were areas of minor corrosion bleed

though the coating (less than 4 square feet) and staining (less than 50

square feet) caused by condensation from the "A" and "B" Cooling filter

lines. The areas of peeling and flaking paint are less than 2 square feet

areas. Engineering evaluated the minor surface condition at various

locations and were found to be acceptable. The minor degraded areas

are monitored every refueling outage.

* The drywell shell to floor caulked seal is inspected every refueling

outage. A general visual examination is performed looking for cracking,

peeling, delaminating or separation of the seal, discoloration in the

caulking material, and flexibility of the caulking. The caulk seal has not

been removed or replaced.

* Operating experience review at JAFNPP found no occurrences of

leakage into the annulus air gap. In addition, no leakage has been found

through the refueling bellows into the area monitored by the air gap

leakage detection system.

After review of the applicant's response, the staff requested by letter dated April 2, 2007, the

following additional information for the drywell shell exterior:

1 . The paragraph "Drywell Shell Exterior," states that JAFNPP determined

that only one out of four air gap drain lines is required for the function for

which they were designed, to drain condensates that may form in the air

gap. The staff requested JAFNPP to explain the bases of this

requirement.

2. The staff also requested the applicant to address conditions of the

stainless steel plates and adhesive that cover the sand cushion.

In its response dated April 24, 2007, the applicant provided the following information:

1 . The architect engineer, Stone & Webster (SWEC) stated that one of the

four upper sand cushion drain lines would be sufficient to perform the

function of draining any condensates which may form.in the two inch air

gap. Per Attachment 1 to NYPA Memorandum #JTS-88-0848, dated

November 8, 1988, SWEC stated that their search of the project files,

including specifications, calculations and job books did not locate any

design basis for these drains. SWEC further stated that based on a

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preliminary evaluation, one 2" drain line would have enough capacity to

drain any moisture resulting from condensation on the drywell shell. Also,

any condensation caused by cooling of the drywell would return to the

vapor state when the drywell heats up. Therefore, condensation should

not be considered a major concern.

2. As stated in LRA Amendment #6, JAFP-07-0021, page 16, JAFNPP

stated that additional examination of the drywell air gap will be performed

in 2007. Preliminary details of the examination are discussed in response

to RAI 2.4.1-3 in the letter dated April 24, 2007.

The staff finds the applicant's response to RAI 3.5.2-3 acceptable because the applicant (1)

determined that one 2-inch drain line would have enough capacity for its intended functions and

(2) examined the air gap through the drain lines and found no evidence of moisture until now. In

addition, additional inspections will performed as required. The staff's concern described in

RAI 3.5.2-3 is resolved.

In LRA Table 3.5.2-1 under Structure and/or Component or Commodity for "drywell to torus

vent system" and "drywell to torus vent line bellows," the applicant credits the Containment

Inservice Inspection (CII) Program and the Containment Leak Rate Program to manage loss of

material due to general pitting and crevice corrosion and cracking. The vent system, as well as

the vent line bellows, may be inaccessible and subject to corrosion (IN 92-20).

In RAI 3.5.2-4 dated January 12, 2007, the staff requested from the applicant operating

experience and information on how the AMPs will manage aging effects of these components

through the period of extended operation.

In its response dated February 12, 2007, the applicant explained that the drywell to torus vent

system and drywell to torus line bellows are accessible for inspection. As shown in

LRA Table 3.5.2-1, the Containment Inservice Inspection (CII) Program and the Containment

Leak Rate Program manage cracking of stainless steel bellows and loss of material (due to

corrosion) of the carbon steel drywell to torus vent system. These programs are the same as

those of the GALL Report for managing aging effects for these components. Plant-specific

operating experience shows no evidence of degradation from general, pitting, and crevice

corrosion or cracking of the "drywell to torus vent system" and "drywell to torus vent line

bellows."

By letter dated April 2, 2007, the staff asked the applicant how the vent pipe bellows are

monitored for loss of material due to general, pitting, and crevice corrosion and cracking and

whether the applicant has considered Type B tests pursuant to 10 CFR Part 50, Appendix J.

During a March 5, 2007, teleconference, the staff pointed out that Type B tests detect

age-related degradation (i.e., cracking) in the bellows if they are single-plied; however, if the

bellows are double-plied, the applicant must develop specialized Type B tests to pressurize the

space between the two plies or perform Type A tests for that purpose.

The applicant's response dated April 24, 2007, indicated that it manages aging of containment

bellows utilizing Type B tests every 10 years in accordance with 10 CFR Part 50, Appendix J

but did not address the staff's concern.

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Further, the applicant's response dated June 20, 2007, stated that the vent line to torus

penetration bellows consist of two sections of two-ply stainless steel bellows. Type B local

leak-rate testing pressurizes the space between the two plies of each bellows section and

measures leakage as inlet flow to this space to test all of the surface area of each bellows

section effectively. The rest of the penetration assembly, including the vent insert in the torus

shell and mounting plates connecting the bellows to the vent piping and vent insert, is carbon or

stainless steel of welded construction. Type A integrated leak-rate testing pressurizes the

assembly from the torus airspace and measures leakage as inlet flow to the containment to test

all of the surface area of the assembly except the two, two-ply bellows sections effectively.

Therefore, the Type A-Type B combination tests the entire assembly effectively. As noted in the

response to JAFNPP audit question 200, there is no history of exposure of this material to

corrosive contamination nor of corrosion or other degradation of the assembly nor of leakage of

the bellows assemblies under Type A or Type B testing. Exposed inner (i.e., torus side)

surfaces of the assemblies are viewed during Type B testing and during other torus internal

inspections. There is no convenient method for inspecting unexposed assembly portions and no

perceived need from the available history.

Based on its review, the staff finds the applicant's response to RAI 3.5.2-4 acceptable because

the applicant tests all surface areas of the assembly except the two-ply bellows sections tested

by Type B testing in accordance with 10 CFR Part 50, Appendix J. Therefore, the entire

assembly is tested. The staff's concern described in RAI 3.5.2-4 is resolved.

In LRA Table 3.5.2-1, under Structure and/or Component or Commodity for "torus shell," the

applicant credits the Containment Inservice Inspection Program and the Containment Leak

Rate Program to manage loss of material due to general, pitting, and crevice corrosion.

According to IN 2006-01, "Torus Cracking in a BWR Mark I Containment," dated

January 12, 2006, the most likely cause of the through-wall torus crack was cyclic loading due

to condensation oscillation during HPCI operation.

In RAI 3.5.2-5 dated January 12, 2007, the staff requested that the applicant include cracking

as an AERM. Also, the staff requested from the applicant information on how it manages other

areas of the torus susceptible to cracking, pitting corrosion, or both for reasonable assurance

that the torus will function properly through the period of extended operation.

The applicant's response dated February 12, 2007, stated in reference to IN 2006-01 that the

cause of the torus crack was cyclic loading from a design flaw. Specifically, the turbine exhaust

pipe had no sparger and HPCI operation imposed hydrodynamic loading on the torus. As the

flaw resulted from inadequate design rather than aging effect, the appropriate corrective action

would be not an AMP but a design change to install a sparger on the exhaust pipe. Other torus

areas are not susceptible to cracking and areas susceptible to pitting corrosion are included in

the AMPs shown in LRA Table 3.5.2-1. The Containment Inservice Inspection (CII) Program

manages loss of material through visual inspections as described in LRA Section B.16.1.

Based on its review, the staff finds the applicant's response to RAI 3.5.2-5 acceptable because

the applicant explained that the cause of the torus crack was the cyclic loading resulting from a

design flaw not part of the AMP. The corrective action-for inadequate design was fixed by

installation of a sparger; moreover, the applicant stated that other torus areas susceptible to

cracking and pitting corrosion are included in the AMP. The staff's concern described in

RAI 3.5.2-5 is resolved.

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In LRA Table 3.5.2-1, under Structure and/or Component or Commodity for "drywell shell" and

"torus shell," the applicant indicated no TLAA. No TLAA for either drywell or torus corrosion

indicates that neither containment component has experienced degradation requiring such an

analysis.

In RAI 3.5.2-6 dated January 12, 2007, the staff requested that the applicant justify why no

TLAA is required for either component.

The applicant's response dated February 12, 2007, stated that no TLAA for either drywell or

torus corrosion does not indicate that these components have not experienced corrosion. No

TLAA indicates that no analysis meets the 10 CFR 54.3 definition of a TLAA and that the

original design requires none. In fact-there has been corrosion of drywell and torus materials

and environments. As indicated in LRA Table 3.5.2-1, the Containment Inservice Inspection

(CII) Program and the Containment Leak Rate Program manage loss of material, an aging

effect caused by corrosion. These programs are the same as those of the GALL Report for

managing aging effects for such components. In addition, as shown in LRA Table 3.5.2-1, the

"torus shell" refers to "TLAA - metal fatigue." LRA Section 4.6 describes the evaluation of metal

fatigue for the torus and attached piping, the only TLAA for the primary containment.

Based on its review, the staff finds the applicant's response to RAI 3.5.2-6 acceptable because

the applicant explained that no analysis meets the 10 CFR 54.3 definition of a TLAA. The

Containment Inservice Inspection (CII) Program and the Containment Leak Rate Program

manage aging effects on materials due to corrosion. The staff's concern described in

RAI 3.5.2-6 is resolved.

The staff finds the applicant's programs acceptable. Based on the applicant's observations of

no water leakage into the drywell shell area, the staff concludes that the applicant has met

SRP-LR Section 3.5.2.2.1.4 criteria. For those line items to which LRA Section 3.5.2.2.1.4

applies, 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 to maintain

intended functions 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. In LRA

Section 3.5.2.2.1.5, the applicant stated that JAFNPP is a Mark I containment and does not

incorporate prestressed concrete in its design. Therefore, the staff finds that loss of prestress

due to relaxation, shrinkage, creep, and elevated temperature do not apply.

Cumulative Fatigue Damage. In LRA Section 3.5.2.2.1.6, the applicant stated that if included in

the CLB, fatigue analyses of suppression pool steel shells (including welded joints) and

penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) for

all types of PWR and BWR containments and BWR vent header, line bellows, and downcomers

are TLAAs, as defined in 10 CFR 54.3.

SRP-LR Section 3.5.2.2.1.6 states that applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1).

SER Section 4.6 documents the staff's review of the applicant's evaluation of this TLAA.

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Cracking Due to Stress Corrosion Cracking. The staff reviewed LRA Section 3.5.2.2.1.7 against

the criteria in SRP-LR Section 3.5.2.2.1.7.

LRA Section 3.5.2.2.1.7 states that the GALL Report recommends further evaluation of

inspection methods to detect cracking due to SCC since visual VT-3 examinations may be

unable to detect this aging effect. Potentially susceptible components at JAFNPP are

penetration sleeves and bellows.

SCC is an aging mechanism that requires the simultaneous action of a corrosive environment,

sustained tensile stress, and a susceptible material. Elimination of any one of these elements

will eliminate susceptibility to SCC. Stainless steel elements of primary containment and the

containment vacuum breaker system, including dissimilar welds, are susceptible to SCC.

However, these elements are located inside the containment drywell or outside the drywell, in

the reactor building, and are not subject to corrosive environment as discussed below.

The drywell is made inert with nitrogen to render the primary containment atmosphere

non-flammable by maintaining the oxygen content below 4% by volume during normal

operation. The normal operating average temperature inside the drywell is less than 139 0F and

the relative humidity range is 20-40%. The reactor building normal operating temperature range

is 65°F - 92°F, and the maximum relative humidity is 100%. Both the containment atmosphere

and indoor air environments are non-corrosive (chlorides < 150 ppb, sulfates < 100 ppb, and

fluorides 150 < ppb). Thus, SCC is not expected to occur in the containment penetration

bellows, penetration sleeves, and dissimilar metal welds. A review of plant operating experience

did not identify cracking of the components, and primary containment leakage has not been

identified as a concern. Therefore the existing Containment Leakage Rate Program and

Containment Inservice Inspection - IWE are adequate to detect cracking. Observed conditions

that have the potential for impacting an intended function are evaluated or corrected in

accordance with the corrective action process. The Containment Inservice Inspection -IWE and

Containment Leak rate programs are described in Appendix B.

SRP-LR Section 3.5.2.2.1.7 states that cracking due to SCC of stainless steel penetration

sleeves, penetration bellows, and dissimilar metal welds could occur in all types of PWR and

BWR containments. Cracking due to SCC could also occur in stainless steel vent line bellows

for BWR containments. The existing program relies on ASME Section XI, Subsection IWE and

10 CFR Part 50, Appendix J, to manage this aging effect. The GALL Report recommends

further evaluation of additional appropriate examinations/evaluations implemented to detect

these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar

metal welds, and stainless steel vent line bellows.

During interviews with the staff, the applicant stated that the GALL Report's referenced

programs involve visual inspection and leak rate testing, which are not optimum methods for

managing SCC. Therefore, when possible, the "other" method which may be used to detect

cracking is the existing Containment Leak Rate Program, and when necessary, augmented

ultrasonic exams are utilized, which is the optimum method for managing SCC. As described in

LRA Section 3.5.2.2.1.7, SCC is not an AERM for the penetration sleeves and bellows, since

the conditions necessary for SCC do not exist. However, the components are evaluated for

aging effects (e.g., cracking requiring management as shown in LRA Table 3.5.2-1).

Based on the above discussion, the staff found that the applicant has identified IWE as capable

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of detecting leaks caused by SCC. Furthermore, additional materials will not meet the

necessary combinations of material and environment required to produce SCC.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.5.2.2.1.7

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.1.7 for further evaluation. For those line items that apply to

LRA Section 3.5.2.2.1.7, the staff determines that the LRA is consistent with the GALL Report

and the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Cyclic Loading. The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria

in SRP-LR Section 3.5.2.2.1.8.

In LRA Section 3.5.2.2.1.8, the applicant stated that cyclic loading can lead to cracking of steel

and stainless steel penetration bellows, and dissimilar metal welds of BWR containments and

BWR suppression pool shell and downcomers.

With proper design, cracking due to cyclic loading is not expected to occur in the drywell, torus

and associated penetration bellows, penetration sleeves, unbraced downcomers, and dissimilar

metal welds. JAFNPP has experienced cracking of the torus shell near one column support due

to hydrodynamic loads of the turbine exhaust pipe during HPCI operation, coupled with the

highly restrained condition of the torus shell at the torus column support. The condition was not

the effect of aging but rather the effect of inadequate design that led to cracking well before the

end of the original license term. A review of plant operating experience did not identify any other

cracking of the components, and primary containment leakage has not been identified as a

concern. Nonetheless, the existing Containment Leakage Rate Program with augmented

ultrasonic exams and Containment Inservice Inspection - IWE will continue to be used to detect

cracking. Observed conditions that have the potential for impacting an intended function are

evaluated or corrected in accordance with the corrective action process. The Containment

Inservice Inspection -IWE and Containment Leak rate programs are described in Appendix B.

The analysis of cracking due to cyclic loading of the drywell, torus, and associated penetrations

is a TLAA which is evaluated and documented in LRA Section 4.6.

SRP-LR Section 3.5.2.2.1.8 states that cracking due to cyclic loading of suppression pool steel

and stainless steel shells (including welded joints) and penetrations (including penetration

sleeves, dissimilar metal welds, and penetration bellows) could occur for all types of PWR and

BWR containments and BWR vent header, vent line bellows and downcomers. The existing

program relies on ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to

manage this aging effect. However, VT-3 visual inspection may not detect fine cracks. The

GALL Report recommends further evaluation for detection of this aging effect.

For cracking due to cyclic loading of steel, SS and dissimilar metal (DSM) welds for penetration

sleeves, penetration bellows, suppression pool shell, and unbraced downcomers exposed to

indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with

GALL AMP XI.S1, "ASME Section XI, Subsection IWE," and GALL AMP XI.S4,

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"10 CFR Part 50, Appendix J."

However, cracking due to cyclic loading of the carbon steel primary containment mechanical

penetrations (including those with bellows) exposed to a protected-from-weather environment is

managed by the applicant using the Containment Inservice Inspection Program and the

Containment Leak Rate Program.

The staff reviewed the Containment Inservice Inspection Program and its evaluation is

documented in SER Section 3.0.3.3.2. The Containment Inservice Inspection Program

encompasses the ASME Code Section XI, Subsection IWE requirements for managing

cracking of the primary containment and its integral attachments. Because the applicant's

plant-specific Containment Inservice Inspection Program includes the same requirements for

inspection and detection of cracking for the primary containment and its integral attachments as

the ASME Code Section XI, Subsection IWE, the staff found it to be an acceptable

management program for cracking of the primary containment mechanical penetrations

(including those with bellows).

For cracking due to cyclic loading of steel, SS and DSM welds for torus, vent line, vent header,

vent line bellows, and downcomers exposed to indoor uncontrolled air, the GALL Report

recommends programs consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE,"

and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."

However, cracking due to cyclic loading of the stainless steel drywell to torus vent line bellows

exposed to a protected-from-weather environment is managed by the applicant using the

Containment Inservice Inspection Program and the Containment Leak Rate Program.

The staffs evaluation of the Containment Inservice Inspection Program is documented in SER

Section 3.0.3.3.2. The staff's evaluation of the Containment Leak Rate Program is documented

in SER Section 3.0.3.1.1. The Containment Leak Rate Program encompasses the requirements

of 10 CFR Part 50, Appendix J. The Containment Inservice Inspection Program encompasses

the ASME Code Section XI, Subsection IWE requirements for managing cracking of the

primary containment and its integral attachments. Because the applicant's plant-specific

Containment Inservice Inspection Program includes the same requirements for inspection and

detection of cracking for the primary containment and its integral attachments as the ASME

Code Section XI, Subsection IWE, the staff found it to be an acceptable management program

for cracking of the drywell to torus vent line bellows.

During the audit and review, the staff asked the applicant to address the operating experience

for the cracks identified in 2005 and to identify any additional inspections scheduled for the next

inspection period.

In its response, the applicant stated that the cracks identified did not deviate significantly from

the baseline inspection and were identified as "minor cracking." Follow-up actions were

identified and as a result of the inspection no additional inspections were required.

Cracking due to cycle loading is not expected to occur in the drywell, torus, associated

penetration bellows, penetration sleeves, unbraced downcomers, and DSM welds (LRA

Table 3.5.1, Item 3.5.1-12). A review of plant operating experience did not identify cracking of

the components, and primary containment leakage has not been identified as a concern.

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Nonetheless, the Containment Inservice Inspection (IWE), the existing Containment Leak Rate

Program, and, when necessary, augmented ultrasonic exams will continue to be used to detect

cracking. Observed conditions that have the potential for impacting an intended function are

evaluated or corrected in accordance with the corrective action process. The Containment

Inservice Inspection and Containment Leak Rate Programs are described in Appendix B.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.5.2.2.1.8 for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.1.8. For those line items that apply to LRA

Section 3.5.2.2.1.8, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. The staff reviewed LRA

Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9.

In LRA Section 3.5.2.2.1.9, the applicant stated that loss of material due to freeze-thaw of

concrete containments is not applicable since JAFNPP has a Mark I steel containment.

The staff finds this evaluation acceptable in that this aging effect is not applicable to the

applicant's Mark I steel containment.

Cracking Due to Expansion and Reaction with Aggregate, and Increase in Porosity and

Permeability Due to Leaching of Calcium Hydroxide. The staff reviewed LRA

Section 3.5.2.2.1.10 against the criteria in SRP-LR Section 3.5.2.2.1.10.

In LRA Section 3.5.2.2.1.10, the applicant stated that cracking due to expansion and reaction

with aggregates of concrete containments is not applicable since JAFNPP has a Mark I steel

containment.

The staff finds this evaluation acceptable in that this aging effect is not applicable to the

applicant's Mark I steel containment.

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,

which addresses several areas that are discussed below.

Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.

In LRA Section 3.5.2.2.2.1, the applicant stated that JAFNPP concrete structures subject to an

AMR are included in the Structures Monitoring Program and supplemented by other AMPs as

appropriate. This is true for concrete items even if the AMR did not identify AERMs. Aging

effects discussed below for structural steel items are also addressed by the structures

monitoring program. Additional discussion of specific aging effects follow.

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SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of

certain structure/aging effect combinations if they are not covered by the structures monitoring

program. This includes (1) cracking, loss of bond, and loss of material (spalling, scaling) due to

corrosion of embedded steel for Groups 1-5, 7, and 9 structures; (2) increase in porosity and

permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack for

Groups 1-5, 7, and 9 structures; (3) loss of material due to corrosion for Groups 1-5, 7, and 8

structures; (4) loss of material (spalling, scaling) and cracking due to freeze-thaw for

Groups 1-3, 5, and 7-9 structures; (5) cracking due to expansion and reaction with aggregates

for Groups 1-5 and 7-9 structures; (6) cracks and distortion due to increased stress levels from

settlement for Groups 1-3 and 5-9 structures; and (7) reduction in foundation strength, cracking,

differential settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9

structures. The GALL Report recommends further evaluation only for structure/aging effect

combinations that are not within the structures monitoring program. In addition, lock up due to

wear could occur for Lubrite radial beam seats in BWR drywell, RPV support shoes for PWR

with nozzle supports, steam generator supports, and other sliding support bearings and sliding

support surfaces. The existing program relies on the structures monitoring program or ASME

Code Section Xl, Subsection IWF, to manage this aging effect. The GALL Report recommends

further evaluation only for structure/aging effect combinations that are not within the ISI (IWF)

or structures monitoring program.

(1) Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of

Embedded Steel for Groups 1-5, 7, and 9 Structures - The applicant stated in the LRA

that the aging mechanisms associated with cracking, loss of bond, and loss of material

(spalling, scaling) due to corrosion of embedded steel are applicable only to

below-grade concrete/grout structures. The below-grade environment for JAFNPP is not

aggressive, and concrete is designed in accordance with specification ACI 318-63,

"Building Code Requirements for Reinforced Concrete," which results in low permeability

and resistance to aggressive chemical solutions by providing a high-cement,

low-water/cement ratio (0.50 or less), proper curing, and adequate air content (between

3% and 5%). Although specified water/cement ratio's fall outside the established range

of 0.35 to 0.45, given all remaining parameters for durable concrete mix design,

JAFNPP concrete meets the quality requirements of ACI to ensure acceptable concrete

is obtained. Therefore, cracking, loss of bond, and loss of material (spalling, scaling)

due to corrosion of embedded steel are not AERMs for JAFNPP Groups 1-5, 7, and 9

structures.

The staff determined through discussions with the applicant's technical staff and review

of bases documents, that the cracking, loss of bond, and loss of material (spalling,

scaling) due to corrosion of embedded steel for Groups 1-5, 7, and 9 structures are not

plausible aging effects at JAFNPP due to the lack of aggressive groundwater. However,

in a letter dated December 6, 2006 (Commitment No. 16), the applicant will enhance the

Structures Monitoring program to perform an engineering evaluation on a periodic basis

(at least once every five years) of ground water samples to assess aggressiveness (pH

< 5.5, chloride > 500 ppm, and sulfate > 1500 ppm) of ground water to concrete.

JAFNPP concrete is designed in accordance with specification ACI 318-63 with a

high-cement, low-water/cement ratio, proper curing, and adequate air content between 3

and 6 percent. However, the above aging effects for these groups are included within

the Structures Monitoring Program by the applicant. On this basis, the staff finds this

acceptable.

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(2) Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Due

to Aggressive Chemical Attack for Groups 1-5, 7, and 9 Structures - The applicant

stated in the LRA that aggressive chemical attack becomes significant to concrete

exposed to an aggressive environment. Resistance to mild acid attack is enhanced by

using a dense concrete with low permeability and low water-to-cement ratio of less than

0.50. These groups of structures at JAFNPP use a dense low permeable concrete with

an acceptable water-to-cement ratio, which provides an acceptable degree of protection

against aggressive chemical attack. Water chemical analysis results confirm that the

site groundwater is considered to be non-aggressive. JAFNPP concrete is constructed

in accordance with the recommendations in ACI 201.2R-77 for durability.

JAFNPP below-grade environment is not aggressive. Therefore, increase in porosity

and permeability cracking and loss of material (spalling, scaling) due to aggressive

chemical attack are not AERMs for JAFNPP Groups 1-5, 7, and 9 concrete structures.

The staff determined through discussions with the applicant's technical staff that the

increase in porosity and permeability, cracking, and loss of material (spalling, scaling)

due to aggressive chemical attack for Groups 1-5, 7, and 9 structures are not plausible

aging effects at JAFNPP due to the lack of aggressive groundwater and the concrete

being constructed for durability in accordance with the recommendations in

ACl 201.2R-77. However, the above aging effects for these groups are included within

the Structures Monitoring Program by the applicant. On this basis, the staff finds this

acceptable.

(3) Loss of Material Due to Corrosion for Groups 1-5, 7, and 8 Structures - The applicant

stated in the LRA that the JAFNPP Structures Monitoring Program will be used to

manage AERMs for JAFNPP Groups 1-5, 7, and 8 structures.

The staff determined through discussions with the applicant's technical staff and a

review of the basis document that the loss of material due to corrosion for Groups 1-5,

7, and 8 structures is an aging effect which will be managed by the applicant's

Structures Monitoring Program. On this basis, the staff finds this acceptable.

(4) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-3, 5,

and 7-9 Structures - The applicant stated in the LRA that aggregates were in

accordance with specifications and materials conforming to ACI and ASTM standards.

JAFNPP structures are constructed of a dense, durable mixture of sound coarse

aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are

within the limits provided in ACI 318-63, and air entrainment percentages were within

the range prescribed in the GALL Report. Therefore, loss of material (spalling, scaling)

and cracking due to freeze-thaw are not AERMs for JAFNPP Groups 1-3, 5, and 7-9

structures.

The staff determined through discussions with the applicant's technical staff and a

review of the basis document that the loss of material (spalling, scaling) and cracking

due to freeze-thaw for Groups 1-3, 5, and 7-9 structures are not plausible aging effects

at JAFNPP due to concrete being constructed in accordance with ACI and ASTM

standards. However, the above aging effects for these groups are included within the

Structures Monitoring Program by the applicant.

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On this basis, the staff finds this acceptable.

(5) Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5 and 7-9

Structures - The applicant stated in the LRA that the aggregates were selected locally

and were in accordance with specifications and materials conforming to ACI and ASTM

standards at the time of construction, which are in accordance with the

recommendations in ACI 201.2R-77 for concrete durability. JAFNPP structures are

constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate,

cement, water, and admixture. Water/cement ratios are within the limits provided in

ACI 318-63, and air entrainment percentages were within the range prescribed in the

GALL Report. Therefore, cracking due to expansion and reaction with aggregates for

Groups 1-3, 5, and 7-9 structures is not an AERM.

The staff determined through discussions with the applicant's technical staff and a

review of the basis document that the cracking due to expansion and reaction with

aggregates for Groups 1-5 and 7-9 structures are not plausible aging effects at JAFNPP

due to concrete being constructed in accordance with ACI and ASTM standards with a

high-cement, low-water/cement ratio. However, the above aging effects for these groups

are included within the Structures Monitoring Program by the applicant. On this basis,

the staff finds this acceptable..

(6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3

and 5-9 Structures

The applicant stated in the LRA that the Groups 1-3 and 5-9 structures at JAFNPP,

settlement is not a credible event since structures and founded on bedrock. Therefore,

cracks and distortion due to increased stress levels from settlement for Groups 1-3 and

5-9 structures is not an AERM for JAFNPP concrete.

The staff determined through discussions with the applicant's technical staff and a

review of the basis document that the cracks and distortion due to increased stress

levels from settlement for Groups 1-3 and 5-9 structures are not plausible aging effects

due to the nonexistence of these aging mechanisms. The applicant states that the aging

effects due to settlement are not expected at JAFNPP for Groups 1-3 and 5-9 Class I

structures. The JAFNPP Class 1 structures are founded on sound bedrock or supported

by steel pilings which prevent significant settlement. The staff finds acceptable the

applicant's assessment that these aging effects are not applicable to JAFNPP Class I

structures. On the basis that JAFNPP does not have any components from this group,

the staff found that this aging effect is not applicable to JAFNPP.

(7) Reduction in Foundation Strength, Cracking, and Differential Settlement Due to Erosion

of Porous Concrete Subfoundation for Groups 1-3 and 5-9 Structures

The applicant stated in the LRA that the JAFNPP concrete was provided in accordance

with ACl 318-63 requirements resulting in dense, well-cured, high-strength concrete with

low-permeability. Structures are supported on bedrock and erosion of the subfoundation

is not credible since the subfoundation is also eliminating the possibility of loss of soil

resulting in voids below the subgrade. Fluid leakage across the subfoundation is

captured by circumferential drains and inspected for any material loss. Operating history

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has not identified any losses to date and, therefore, reduction in foundation strength,

cracking, and differential settlement due to erosion of porous concrete subfoundation

are not AERMs for JAFNPP Groups 1-3 and 5-9 structures.

The staff determined through discussions with the applicant's technical staff that

reduction in foundation strength, cracking, and differential settlement due to erosion of

porous concrete subfoundation for Groups 1-3 and 5-9 structures are not plausible

aging effects due to the nonexistence of these aging mechanisms. The applicant states

that the aging effects of reduction in foundation strength, cracking, and differential

settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9

structures are not applicable to JAFNPP since there are no porous concrete

subfoundations of concern below these structures. The staff finds acceptable the

applicant's assessment that these aging effects are not applicable to.JAFNPP Groups

1-3 and 5-9 structures.

(8) Lockup Due to Wear for Lubrite® Radial Beam Seats in BWR Drywell and Other Sliding

Support Surfaces - The applicant stated in the LRA that owing to wear-resistant material

used, the low frequency (number of times) of movement, and the slow movement

between sliding surfaces, lockup due to wear is not an AERM at JAFNPP. However,

Lubrite® plates are included within the Structures Monitoring Program and Inservice

Inspection (ISI-IWF) Programs to confirm the absence of AERMs for this component.

The staff determined through discussions with the applicant's technical staff that the

lockup due to wear for Lubrite® radial beam seats in BWR drywell and other sliding

support surfaces is not a plausible aging effect at JAFNPP due to the wear-resistant

material used, the low frequency (number of times) of movement, and the slow

movement between sliding surfaces. However, the above aging effects for Lubrite®

components associated with the JAFNPP drywell beam seats are included within the

Structures Monitoring Program by the applicant.

The staff determined through discussions with the applicant's technical staff that the

applicant has included the above eight structure/aging effect combinations in its

Structures Monitoring Program, and no further evaluation is required in accordance with

the GALL Report. However, although not required, the applicant has elected to provide

further evaluation for each of the eight aging effects referenced above. The staff found

this additional evaluation acceptable.

The staff found that, based on the programs identified above, the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.1 for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.1. For those line items that apply to LRA

Section 3.5.2.2.2.1, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Aqing Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against

the SRP-LR Section 3.5.2.2.2.2 criteria.

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In LRA Section 3.5.2.2.2.2, the applicant stated that JAFNPP concrete for Groups 1-3, 5, and

7-9 inaccessible concrete areas was provided in accordance with specification ACI 318-63,

"Building Code Requirements for Reinforced Concrete," which requires the following, resulting

in low permeability and resistance to aggressive chemical solution:

" high cement content

" low water permeability

proper curing

* adequate air entrainment

JAFNPP concrete also meets the requirements of later AcI guide ACI 201.2R-77, "Guide to

Durable Concrete," since both documents use the same ASTM standards for selection,

application, and testing of concrete.

Inspections of accessible concrete have not revealed degradation related to corrosion of

embedded steel. The site's below-grade environment is not aggressive (pH > 5.5, chlorides <

500 ppm, and sulfates < 1500 ppm). Therefore, corrosion of embedded steel is not an AERM

for JAFNPP concrete.

The staff reviewed LRA Section 3.5.2.2.2.2 against the SRP-LR Section 3.5.2.2.2.2 criteria.

(1) Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in

below-grade inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures. The GALL

Report recommends further evaluation of this aging effect for inaccessible areas of

these groups of structures for plants located in moderate to severe weathering

conditions.

(2) Cracking due to expansion and reaction with aggregates could occur in below-grade

inaccessible concrete areas for Groups 1-5 and 7-9 structures. The GALL Report

recommends further evaluation of inaccessible areas of these groups of structures if

concrete was not constructed in accordance with the recommendations in

ACI 201.2R-77.

(3) Cracks and distortion due to increased stress levels from settlement and reduction of

foundation strength, cracking, and differential settlement due to erosion of porous

concrete subfoundations could occur in below-grade inaccessible concrete areas of

Groups 1-3, 5, and 7-9 structures. The existing program relies on structures monitoring

program to manage these aging effects. Some plants may rely on a de-watering system

to lower the site ground water level. If the plant's CLB credits a de-watering system, the

GALL Report recommends verification of the continued functionality of the de-watering

system during the period of extended operation. The GALL Report recommends no

further evaluation if this activity is included within the scope of the applicant's structures

monitoring program.

(4) Increases in porosity and permeability, cracking, loss of material (spalling, scaling) due

to aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling,

scaling) due to corrosion of embedded steel could occur in below-grade inaccessible

concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends

further evaluation of plant-specific programs to manage these aging effects in

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inaccessible areas of these groups of structures if the environment is aggressive.

(5) Increases in porosity and permeability, and loss of strength due to leaching of calcium

hydroxide could occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and

7-9 structures. The GALL Report recommends further evaluation of this aging effect for

inaccessible areas of these groups of structures if concrete was not constructed in

accordance with the recommendations in ACI 201.2R-77.

The staff determined through discussions with the applicant's technical staff that the aging

management of inaccessible areas due to aggressive chemical attack for Groups 1-5, 7, and 9

structures are not plausible aging effects at JAFNPP due to the lack of aggressive groundwater

and the concrete being constructed in accordance with the recommendations in ACl 201.2R-77

for durability with a high-cement, low-water/cement ratio. The applicant will perform

opportunistic inspections of inaccessible concrete areas when they become accessible under

the Buried Piping Inspection Program and the Structures Monitoring Program. In its response

dated December 6, 2006, the applicant provided a list of commitments. Commitment No. 16 will

revise the Structures Monitoring Program to require opportunistic inspections of inaccessible

concrete areas when they become accessible. Furthermore, as part of the structural monitoring

program, the applicant will continue to perform periodic groundwater monitoring to confirm lack

of aggressiveness.

The staff found that, based on the programs identified above and the commitment, the

applicant has met the criteria of SRP-LR Sections 3.5.2.2.2.2.1 through 3.5.2.2.2.2.5 for further

evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.2. For those line items that apply to LRA

Section 3.5.2.2.2.2, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The

staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3.

In LRA Section 3.5.2.2.2.3, the applicant stated that ACI 349 specifies concrete temperature

limits for normal operations or any other long-term period. The temperatures shall not exceed

150 OF except for local areas, which are allowed to have increased temperatures not to exceed

200 OF.

Groups 1-5 concrete elements do not exceed the temperature limits associated with aging

degradation due to elevated temperature. Therefore, reduction of strength and modulus of

concrete due to elevated temperatures is not an AERM for JAFNPP.

SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due to

elevated temperatures could occur in PWR and BWR Group 1-5 concrete structures. For any

concrete elements that exceed specified temperature limits, further evaluations are

recommended. Appendix A of ACI 349-85 specifies the concrete temperature limits for normal

operation or any other long-term period. The temperatures shall not exceed 150 OF except for

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local areas, which are allowed to have increased temperatures not to exceed 200 'F. The GALL

Report recommends further evaluation of a plant-specific program if any portion of the

safety-related and other concrete structures exceeds specified temperature limits (i.e., general

area temperature greater than 66 0C (150 OF) and local area temperature greater than 93 0C

(200 OF)).

The staff determined through discussions with the applicant's technical staff that the reduction

of strength and modulus of concrete structures due to elevated temperatures is not a plausible

aging effect due to the nonexistence of these aging mechanisms. The applicant states that the

aging effects due to elevated temperature are not expected at JAFNPP for the concrete

associated with Groups 1-5 structures since general area temperatures within the primary

containment do not exceed 150°F and local area temperatures do not exceed 200 0 F. The staff

finds acceptable the applicant's assessment that these aging effects are not applicable to the

JAFNPP Groups 1-5 structures concrete.

During the audit and review, the staff asked the applicant to provide the maximum temperatures

that concrete experiences in Groups 1-5 structures.

During interviews with the staff, the applicant's technical staff stated that the JAFNPP concrete

is expected to experience a maximum, normal operation temperature of 150'F (UFSAR

Table 5.2-3). For structures outside the drywell, the bulk area maximum temperature is 120'F

for Groups 1-5 structures as identified in UFSAR Section 7.1.12. Concrete within the drywell

consists of the reactor pedestal, sacrificial shield wall, and the drywell floor. Assurance that bulk

concrete temperatures within the drywell remain below 150°F is obtained through maintaining

average bulk containment temperature within the limits allowed by JAFNPP Technical

Specification Section B3.6.1.5. Although upper elevations of the drywell may exceed 150 0 F, the

concrete of the drywell is at lower elevations. The drywell cooling system provides cooling to

ensure temperature limits are not exceeded. The highest concrete temperature in the drywell is

at the sacrificial shield wall. The concrete in this wall is not load bearing.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.3. For those line items that apply to LRA

Section 3.5.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Aging Mana-qement of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA

Section 3.5.2.2.2.4 against the SRP-LR Section 3.5.2.2.2.4 criteria.

For inaccessible areas of certain Group 6 structures, aging effects are covered by inspections

in accordance with the Structures Monitoring Program.

(1) LRA Section 3.5.2.2.2.4 states that below-grade exterior reinforced concrete at JAFNPP

is not exposed to 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 1500

ppm sulfate). Therefore, increase in porosity and permeability, cracking, loss of material

(spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of

material (spalling, scaling)/corrosion of embedded steel are not AERMs for below-grade

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inaccessible concrete areas of JAFNPP Group 6 structures.

SRP-LR Section 3.5.2.2.2.4 states that increase in porosity and permeability, cracking,

loss of material (spalling, scaling)/ aggressive chemical attack; and cracking, loss of

bond, and loss of material (spalling, scaling)/ corrosion of embedded steel could occur in

below-grade inaccessible concrete areas of Group 6 structures. The GALL Report

recommends further evaluation of plant-specific programs to manage these aging

effects in inaccessible areas if the environment is aggressive.

The staff determined through discussions with -the applicant's technical staff that the

increase in porosity and permeability, cracking, loss of material (spalling,

scaling)/aggressive chemical attack; andcracking, loss- of bond), and .loss of material

(spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete

areas of Group 6 structures are not significant aging effects at JAFNPP due to the lack

of aggressive groundwater and the concrete being constructed for durability with a

high-cement, low-water/cement ratio, in accordance with the recommendations in

ACI 201.2R-77. The applicant will perform opportunistic inspections of inaccessible

concrete areas when they become accessible under the Buried Piping Inspection

Program and the Structures Monitoring Program. In its response dated December 6,

2006, the applicant provided a list of commitments. Commitment No. 16 will revise the

Structures Monitoring Program to require opportunistic inspections of inaccessible

concrete areas when they become accessible. Furthermore, as part of the structural

monitoring program, the applicant will continue to perform periodic groundwater

monitoring to confirm lack of aggressiveness.

The staff finds that, based on the programs identified above, the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.4.1 for further evaluation.

(2) In LRA Section 3.5.2.2.2.4, the applicant stated that for the loss of material (spalling,

scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of

Group 6 structures, this aging effect is not applicable to JAFNPP because the

aggregates were selected locally and were in accordance with specifications and

materials conforming to ACI and ASTM standards at the time of construction. JAFNPP

structures are constructed of a dense, durable mixture of sound coarse aggregate, fine

aggregate, cement, water, and admixture. Water/cement ratios are within the limits

provided in ACI 318-63, and air entrainment percentages were within the range

prescribed in the GALL Report. Therefore, loss of material (spalling, scaling) and

cracking due to freeze-thaw are not AERMs for JAFNPP Group 6 structures.

SRP-,LR Section 3.5.2.2.2.4 states 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.

The staff determined through discussions with the applicant's technical staff that the

loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade

inaccessible concrete areas of Group 6 structures are not aging effects at JAFNPP due

to concrete being constructed in accordance with ACI and ASTM standards with a

high-cement, low-water/cement ratio. The staff finds that the applicant has

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demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21(a)(3).

The staff finds that, based on the programs identified above and the LRA amendment,

the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4.2 for further evaluation.

(3) In LRA Section 3.5.2.2.2.4, the applicant addressed that for cracking due to expansion

and reaction with aggregates, increase in porosity and permeability, and loss of strength

due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of

Group 6 structures, this aging effect is not applicable to JAFNPP because the

aggregates were selected locally and were in accordance with specifications and

materials conforming to ACI and ASTM standards at the time of construction, which are

in accordance with the recommendations in ACI 201.2R-77 for concrete durability.

JAFNPP structures are constructed of a dense, durable mixture of sound coarse

aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within

the limits provided in ACI 318-63, and air entrainment percentages were within the range

prescribed in the GALL Report. JAFNPP below-grade environment is not aggressive (pH

> 5.5, chlorides < 500 ppm, and sulfates < 1500 ppm).

SRP-LR Section 3.5.2.2.2.4 states that cracking due to expansion and reaction with

aggregates and increase in porosity and permeability, and loss of strength due to

leaching of calcium hydroxide could occur in below-grade inaccessible reinforced

concrete areas of Group 6 structures. The GALL Report recommends further evaluation

of inaccessible areas if concrete was not constructed in accordance with the

recommendations in ACI 201.2R-77.

The staff determined through discussions with the applicant's technical staff that the

•cracking due to expansion and reaction with aggregates and the increase in porosity and

permeability due to leaching of calcium hydroxide in below-grade, inaccessible concrete

areas of Group 6 structures is not an aging mechanism for JAFNPP concrete. The staff

determined through discussions with the applicant's technical staff that cracking due to

expansion and reaction with aggregates, increase in porosity and permeability, and loss

of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete

areas of Group 6 structures are not aging effects at JAFNPP due to concrete being

constructed in accordance with ACl and ASTM standards with a high-cement,

low-water/cement ratio and the below-grade environment being nonaggressive. However,

the above aging effects for this group are included within the Structures Monitoring

Program by the applicant.

The staff found that, based on the programs identified above and the LRA amendment,

the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4(3) for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.4. For those line items that apply to LRA

Section 3.5.2.2.2.4, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

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Crackinq Due to Stress Corrosion Cracking and Loss of Material Due to Pittinq and Crevice

Corrosion. The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR

Section 3.5.2.2.2.5.

In LRA Section 3.5.2.2.2.5, the applicant stated that no tanks with SS liners are included in the

structural AMRs. Tanks subject to AMR are evaluated with their respective mechanical systems.

SRP-LR Section 3.5.2.2.2.5 states that cracking due to stress corrosion cracking and loss of

material due to pitting and crevice corrosion could occur for Group 7 and 8 stainless steel tank

liners exposed to standing water. The GALL Report recommends further evaluation of

plant-specific programs to manage these aging effects.

The staff determined through discussions with the applicant's technical staff that the cracking

due to SCC and loss of material due to pitting and crevice corrosion are not AERMs at JAFNPP

since there are no tanks with SS liners included in the structural AMRs. Tanks subject to an

AMR are evaluated with their respective mechanical systems.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.5. For those line items that apply to LRA

Section 3.5.2.2.2.5, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Aging of Supports Not Covered by Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6.

In LRA Section 3.5.2.2.2.6, the applicant addressed that the GALL Report recommends further

evaluation of certain component support/aging effect combinations if they are not covered by the

applicant's Structures Monitoring Program. Component supports at JAFNPP are included in the

Structures Monitoring Program for Groups B2 through B5 and Inservice Inspection (ISI-IWF)

Program for Group BI.

SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation of

certain component support/aging effect combinations if they are not covered by the structures

monitoring program. This includes (1) loss of material due to general and pitting corrosion, for

Groups B2-B5 supports; (2) reduction in concrete anchor capacity due to degradation of the

surrounding concrete, for Groups B1-B5 supports; and (3) reduction/loss of isolation function

due to degradation of vibration isolation elements, for Group B4 supports. Further evaluation is

necessary only for structure/aging effect combinations not covered by the structures monitoring

program.

(1) Reduction in concrete anchor capacity due to degradation of the surrounding concrete for

Groups B1 through B5 supports.

JAFNPP concrete anchors and surrounding concrete are included in the Structures

Monitoring Program (Groups B2 through B5) and Inservice Inspection (ISI-IWF) Program

(Group B1).

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(2) Loss of material due to general and pitting corrosion for Groups B2 through B5 supports

Loss of material due to corrosion of steel support components is an AERM at JAFNPP.

This aging effect is managed by the Structures Monitoring Program.

(3) Reduction/loss of isolation function due to degradation of vibration isolation elements for

Group B4 supports

The JAFNPP AMR did not identify any component support structure/aging effect

combination corresponding to the GALL Report, Volume 2, Item III.B4.2-a.

The staff finds that the applicant has included the above AEM combinations within the scope of

its Structures Monitoring Program or Inservice Inspection (IWF) Program and finds that no

further evaluation is required. The staff determined through discussions with the applicant's

technical staff that reduction/loss of isolation function due to degradation of vibration isolation

elements for Group B4 supports is not an AERM at JAFNPP since there are no vibration

isolation components within the scope of license renewal. The staff reviewed the applicant's

Structures Monitoring Program and Inservice Inspection (IWF) Program, and these evaluations

are documented in Section 3.0.3.2.18 and Section 3.0.3.3.3 of this SER, respectively. The staff

finds the applicant's Structures Monitoring Program and Inservice Inspection (IWF) Program

acceptable for managing the above AEM combinations of component supports for the GALL

Report component support Groups B1 through B5, as those combinations are applicable.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.5.2.2.2.6 for further evaluation.

Based on the programs identified above, the staff concludes that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.6. For those line items that apply to LRA

Section 3.5.2.2.2.6, the staff determines that the LRA is consistent with the GALL Report and

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cumulative Fatigue Damage Due to Cyclic Loading. In LRA Section 3.5.2.2.2.7, the applicant

stated that TLAAs are evaluated in accordance with 10 CFR 54.21(c) as documented in LRA

Section 4. During the process of identifying TLAAs in the JAFNPP CLB, no fatigue analyses

were identified for component support members, anchor bolts, and welds for Groups B1.1, B1.2,

and B1.3.

The staff determined through discussions with the applicant's technical personnel that there are

no CLB fatigue analyses for component support members, anchor bolts, and welds for

Groups B1.1, B1.2, and B1.3 and, therefore, cumulative fatigue damage cannot be evaluated as

an aging effect for these components. Therefore, cumulative fatigue damage for Groups B1.1,

B1.2 and B1.3 component supports is not a TLAA as defined in 10 CFR 54.3.

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program safety-related

and nonsafety-related components.

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

Summary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-4, the

staff reviewed additional details concerning the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are 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 a line

item in the GALL Report. The applicant provided further information concerning how the aging

effects will be managed. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in.the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination is

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

Structure and Component Supports AMR Line Items That Have No Aging Effects (LRA

Tables 3.5.2-1 through 3.5.2-4). In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified

AMR line items where no aging effects were identified as a result of its aging review process.

Specifically, instances in which the applicant states that no aging effects were identified occurred

when components fabricated from concrete material are exposed to a protected-from-weather,

exposed-to-weather, or fluid environment. In the LRA, the applicant states that inaccessible and

accessible concrete areas are designed in accordance with ACI specification ACI 318-63,

"Building Code Requirements for Reinforced Concrete," which results in low permeability and

resistance to aggressive chemical solutions by requiring the following:

" high cement content

" low water-to-cement ratio

• proper curing

" adequate air entrainment

JAFNPP concrete also meets requirements of later ACI guide ACI 201.2R-77, "Guide to Durable

Concrete," since both ACI documents use the same ASTM standards for selection, application,

and testing of concrete. The below-grade environment is not aggressive (pH > 5.5, chlorides <

500 ppm, and sulfates < 1500 ppm). Concrete was provided with air content between 3 and 5%

and, in general, a water/cement ratio between 0.44 and 0.60. Therefore, increase in porosity and

permeability due to leaching of calcium hydroxide, cracking, loss of material (spalling, scaling)

due to aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling,

scaling) due to corrosion of embedded steel are not applicable to concrete in accessible and

inaccessible areas.

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Aggregates used at JAFNPP were in accordance with specifications and materials conforming to

ACI and ASTM standards. JAFNPP concrete structures are constructed of a dense, durable

mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Therefore,

loss of material (spalling, scaling) and cracking due to freeze-thaw and cracking due to

expansion and reaction with aggregates are not AERMs for JAFNPP structures. ASME Code,

Section III, Division 2, Subsection CC, indicates that aging due to elevated temperature

exposure is not significant as long as concrete general area temperatures do not exceed 150°F

and local area temperatures do not exceed 200'F. During normal operation, areas within the

JAFNPP primary containment and other structures are within these temperature limits.

Therefore, reduction of strength and modulus of concrete structures due to elevated

temperature is not an AERM for JAFNPP concrete. However, the applicant has elected to

confirm the absence of concrete aging effects under its Structures Monitoring Program.

The staff found that the quality of the reinforced concrete used at JAFNPP meets the codes and

standards referenced in the GALL Report such that the concrete is not susceptible to the aging

effects listed above. The below-grade environment was found not to be aggressive at JAFNPP,

with continuing groundwater monitoring to occur during the period of extended license.

Therefore, no aging effects are considered to be applicable to components fabricated from

concrete material protected from weather, exposed to weather, or exposed to fluid

environments. However, JAFNPP will confirm the absence of concrete aging effects under its

Structures Monitoring Program.

On the basis of its review of current industry research and operating experience, the staff found

that protected-from-weather, exposed-to-weather, or exposed-to-fluid concrete components will

not result in aging that will be of concern during the period of extended operation. The staff finds

that the applicant's AMR evaluations concerning potential aging effects are acceptable.

Therefore, the staff concluded that there are no applicable AERMs for concrete components

exposed to protected-from-weather, exposed-to-weather, or exposed-to-fluid environments

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified AMR line items where no aging

effects were identified as a result of its aging review process. Specifically, instances in which the

applicant states that no aging effects were identified occurred when components fabricated from

Lubrite® plate material were in a protected-from-weather environment. In the LRA, the applicant

states that Lubrite® plates are used in the drywell beam seats and the torus support saddles at

JAFNPP. Lubrite® materials for nuclear applications are designed to resist deformation, have a

low coefficient of friction, resist softening at elevated temperatures, resist corrosion, withstand

high intensities of radiation, and not score or mar; therefore, they are not susceptible to AERMs.

Due to the wear-resistant material used, the low frequency (number of times) of movement, and

the slow movement between sliding surfaces, lockup and loss of mechanical function of Lubrite®

plates from wear, corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic

thermal loads are not considered to be AERMs at JAFNPP. Nonetheless, Lubrite® plates are

included within the Structures Monitoring Program and Inservice Inspection (IWF) Program. The

staff found that industry operating experience and JAFNPP ISI inspection reports for

slide-bearing plates have identified no recordable degradation due to any aging effects.

Therefore, no aging effects are considered to be applicable to components fabricated from

Lubrite® plate material exposed to a protected-from-weather environment.

On the basis of its review of current industry research and operating experience, the staff found

that a protected-from-weather environment on Lubrite® plate will not result in aging that will be of

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concern during the period of extended operation. The staff finds acceptable the applicant's AMR

evaluations that Lubrite® plate in a protected-from-weather environment will have no identified

aging effects that actually occur. Therefore, the staff concluded that there are no applicable

AERMs for Lubrite® plate components exposed to a protected-from-weather environment.

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified AMR line items where no aging

effects were identified as a result of its aging review process. Specifically, instances in which the

applicant states that no aging effects were identified occurred when components fabricated from

aluminum material were in a exposed-to-weather environment.

In the LRA, the applicant states that the ambient environment at JAFNPP is not chemically

polluted by vapors of sulfur dioxide or other similar substances and the external environment

does not contain saltwater or high chlorides. In this nonaggressive environment, the occasional

wetting and drying from normal outdoor weather does not result in any significant loss of material

for aluminum components. Therefore, loss of material due to pitting and crevice corrosion is not

an AERM for aluminum components exposed to a weather environment. The staff found that

industry operating experience and previously approved staff positions support the conclusion

that there are no aging effects for aluminum in a weather environment. Therefore, no aging

effects are considered- to be applicable to components fabricated from aluminum material

exposed to a weather environment.

On the basis of its review of current industry operating experience and approved staff positions,

the staff found that a weather environment on aluminum at JAFNPP will not result in aging that

will be of concern during the period of extended operation. The staff finds acceptable the

applicant's AMR evaluations that aluminum in a weather environment will have no identified

aging effects that actually occur. Therefore, the staff concluded that there are no applicable

AERMs for aluminum components exposed to a weather environment.

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified AMR line items where no aging

effects were identified as a result of its aging review process. Specifically, instances in which the

applicant states that no aging effects were identified occurred when components fabricated from

SS material were in a exposed-to-weather environment.

In the LRA, the applicant states that the ambient environment at JAFNPP is not chemically

polluted by vapors of sulfur dioxide or other similar substances and the external environment

does not contain saltwater or high chlorides. In this nonaggressive environment, the occasional

wetting and drying from normal outdoor weather does not result in any significant loss of material

for SS components. Therefore, loss of material due to pitting and crevice corrosion is not an

AERM for SS components exposed to a weather environment. The staff found that industry

operating experience and previously approved staff positions support the conclusion that there

are no aging effects for SS in a weather environment. Therefore, no aging. effects are

considered to be applicable to components fabricated from SS material exposed to a weather

environment.

On the basis of its review of current industry operating experience and approved staff positions,

the staff found that a weather environment on SS at JAFNPP will not result in aging that will be

of concern during the period of extended operation. The staff finds acceptable the applicant's

AMR evaluations that SS in a weather environment will have no identified aging effects that

actually occur. Therefore, the staff concluded that there are no applicable AERMs for SS

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components exposed to a weather environment.

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified AMR line items where no aging

effects were identified as a result of its aging review process. Specifically, instances in which the

applicant states that no aging effects were identified occurred when components fabricated from

Pyrocrete® material were in a protected-from-weather environment.

The staff noted that in LRA Table 3.5.2-4 (page 3.5-82), for component fireproofing, the aging

effect for Pyrocrete® material in a protected-from-weather environment is none.

During the audit and review, the staff asked the applicant to provide a technical basis as to why

Pyrocrete® does not have any aging effects in the environment listed.

During interviews with the staff, the applicant's staff stated that Pyrocrete® (used for fireproofing)

is a cement base composite material. Pyrocrete® is not identified in the GALL Report. As such,

JAFNPP's technical evaluation of Pyrocrete® in determining applicable aging effects was the

same as that for concrete, which is based on EPRI 1002950, "Aging Effects for Structures and

Structural Components (Structural Tools)," Revision 1, Section 5. Accordingly, no aging effects

were determined for Pyrocrete® protected from weather. However, as indicated in LRA

Table 3.5.2-4 (page 3.5-82), the Fire Protection Program and Structures Monitoring Program will

confirm the absence of significant aging effects throughout the period of extended operation.

The staff found Pyrocrete® to be a cementitious material that, like concrete in a

protected-from-weather environment, will not experience aging effects. Industry operating

experience supports the conclusion that there are no aging effects for Pyrocrete® in a

protected-from-weather environment. Therefore, no aging effects are considered to be

applicable to components fabricated from Pyrocrete® material exposed to a

protected-from-weather environment. Nonetheless, PyrocreteD is included within the Fire

Protection Program and Structures Monitoring Program to ensure aging effects such as cracking

or loss of material are not occurring.

On the basis of current industry research and operating experience, the staff found that a

protected-from-weather environment on Pyrocrete® at JAFNPP will not result in aging that will be

of concern during the period of extended operation. The staff finds acceptable the applicant's

AMR evaluations that Pyrocrete® in a protected-from-weather environment will have no identified

aging effects that actually occur. Therefore, the staff concluded that there are no applicable

AERMs for Pyrocrete® components exposed to a protected-from-weather environment.

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant identified AMR line items where no aging

effects were identified as a result of its aging review process. Specifically, instances in which the

applicant states that no aging effects were identified occurred when components fabricated from

fiberglass, calcium silicate, or Stratafab® material were in a protected-from-weather environment.

In the LRA, the applicant states that loss of insulating characteristics due to insulation

degradation is not an AERM for insulation material. Insulation products (i.e., made from

fiberglass fiber, calcium silicate, SS, and similar materials) that are protected from weather do

not experience aging effects that would significantly degrade their ability to insulate as designed.

A review of site operating experience identified no aging effects for insulation used at JAFNPP.

No aging effects are considered to be applicable to components fabricated from fiberglass,

calcium silicate, or Stratafab® material exposed to a protected-from-weather environment.

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On the basis of its review of current industry research and operating experience, the staff found

that a protected-from-weather environment on fiberglass, calcium silicate, or Stratafab® will not

result in aging that will be of concern during the period of extended operation. Therefore, the

staff concluded that there are no applicable. AERMs for fiberglass, calcium silicate, or Stratafab®

components exposed to protected-from-weather environments.

3.5.2.3.1 Reactor Building and Primary Containment Summary of Aging Management

Evaluation - LRA Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the

reactor building and primary containment component groups.

In LRA Table 3.5.2-1, the applicant proposed the Structures Monitoring Program to manage

cracking and change in material properties- of concrete in floor slab and wall component types

exposed to environments protected from weather.

SER Section 3.0.3.2.18 documents the staff evaluation of the applicant's Structures Monitoring

Program, which visually inspects Concrete structures for cracking and change in material

properties. On this basis, the staff finds management of cracking and change in material

properties of concrete material acceptable.

In LRA Table 3.5.2-1, the applicant proposed the Water Chemistry Control - BWR Program to

manage loss of material of stainless materials for spent fuel pool storage rack component types

exposed to fluid environments.

The staff noted that LRA Table 3.5.2-1 shows loss of material as an aging effect for SS spent

fuel pool storage racks in environments exposed to fluid. The staff asked the applicant to explain

the aging mechanism for loss of material and why cracking is not an aging effect for such

components.

During interviews the applicant's technical personnel stated that, as in LRA Table 3.5.2-1, the

aging effect for spent fuel pool storage racks is loss of material. The specific aging mechanisms

are pitting and crevice corrosion because SS is susceptible to this aging mechanism when

exposed to oxygen in a treated water environment. Cracking is not an AERM for SS in the spent

fuel pool because SCC depends on temperature (greater thanl40 OF). The spent fuel pool

treated water environment temperature is less than 140 OF.

SER Section 3.0.3.1.10 documents the staff evaluation of the applicant's Water Chemistry

Control - BWR Program, which manages aging effects caused by corrosion and cracking

mechanisms. The program monitors and controls water chemistry according to EPRI

Report 1008192 (BWRVIP-130). EPRI guidelines in BWRVIP-130 recommend control of water

chemistry in the spent fuel pool. The staff accepts the position that the Water Chemistry Control

- BWR Program properly manages loss of SS spent fuel pool storage rack material exposed to

fluid environments through the addition of chemicals to reduce the amount of dissolved oxygen

in the spent fuel pool treated water and SS pitting and crevice corrosion.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff finds that the Water Chemistry Control - BWR Program effectively manages the aging

effect of loss of SS material exposed to fluid environments. On this basis, the staff finds

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management of loss of SS spent fuel pool storage rack material in the reactor building

acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results for material, environment, AERMs, 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 to maintain intended function(s) 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 Evaluation -

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.

The staff reviewed the information provided in LRA Table 3.5.2-2, and determined that the

applicant has adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the JAFNPP Water Control Structures.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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 Complex and Yard Structures Summary of Aging Management

Evaluation - LRA Table 3.5.2-3

The staff reviewed the information provided in LRA Table 3.5.2-3, and determined that the

applicant has adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the JAFNPP Turbine Building Complex and Yard Structures.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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(sy 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 Evaluation - 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.

The staff reviewed the information provided in LRA Table 3.5.2-4, and determined that the

applicant has adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the JAFNPP Bulk Commodities Component Groups.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are not evaluated in

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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 components, that are within the

scope of license renewal and subject to an AMR, will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff's review of the applicant's AMR results for the

electrical and instrumentation and controls components and component groups of the following:

* insulated cables and connections

a metal-enclosed bus

0 transmission conductors

0 switchyard bus

0 high-voltage insulators

• 115kV oil-filled cable system

3.6.1 Summary of Technical Information in the Application

In LRA Section 3.6, the applicant provided AMR results for the electrical and instrumentation and

controls components and component groups. In LRA Table 3.6.1, "Summary of Aging

Management Programs for the Electrical and I&C Components," the applicant provided a

summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical

and instrumentation and controls components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the electrical and instrumentation and

controls components, that are within the scope of license renewal and subject to an AMR, will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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The staff conducted an onsite audit of AMRs to confirm the applicant's claim that certain

identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff did verify that the material presented

in the LRA was applicable and that the applicant identified the appropriate GALL 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 that were 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 acceptance criteria in SRP-LR Section 3.6.2.2. The staff's

audit evaluations are documented in SER Section 3.6.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and whether the aging

effects listed were appropriate for the combination of materials and environments specified. The

staff's audit evaluations are documented in SER Section 3.6.2.3. The staff's evaluation of the

technical review is also documented in SER Section 3.6.2.3.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the electrical and instrumentation and controls components.

Table 3.6-1, provided below, includes a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs, listed in LRA Section 3.6, that are addressed in the GALL

Report.

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

Report

Component Aging Effect/ AMP in GALL AMP in LRA Staff

Group Mechanism Report Evaluation

(GALL Report

Item No.)

Electrical equipment Degradation due to Environmental TLAA Consistent with

subject to various aging Qualification of GALL Report, which

10 CFR 50.49 mechanisms Electric recommends further

environmental Components evaluation (See

qualification (EQ) SER

requirements Section 3.6.2.2.1)

(3.6.1-1)

Electrical cables, Reduced insulation Electrical Cables Non-EQ Insulated Consistent with

connections and resistance and and Connections Cables and GALL Report, which

fuse holders electrical failure due Not Subject to Connections recommends no

(insulation) not to various physical, 10 CFR 50.49 Program (B.1.19) further evaluation

subject to thermal, radiolytic, EQ Requirements (See SER

10 CFR 50.49 photolytic, and Section 3.6.2.1)

EQ requirements chemical

(3.6.1-2) mechanisms

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Component Aging Effect/ AMP in GALL AMP in LRA Staff

Group Mechanism Report Evaluation

(GALL Report

Item No.)

Conductor Reduced insulation Electrical Cables Non-EQ Consistent with

insulation for resistance and And Connections Instrumentation GALL Report, which

electrical cables and electrical failure due Used In Circuits Test Review recommends no connections used in to various physical, Instrumentation Program (B.1.18) further evaluation

instrumentation thermal, radiolytic, Circuits Not Subject (See SER

circuits not subject photolytic, and To 10 CFR 50.49 Section 3.6.2.1)

to 10 CFR 50.49 chemical EQ Requirements

EQ requirements mechanisms

that are sensitive to

reduction in

conductor insulation

resistance (IR)

(3.6.1-3)

Conductor Localized damage Inaccessible None Not consistent with

insulation for and breakdown of Medium Voltage GALL Report (See

inaccessible insulation leading to Cables Not Subject SER

medium voltage electrical failure due to 10 CFR 50.49 Section 3.6.2.3)

(2 kV to 35 kV) to moisture EQ Requirements

cables intrusion, water

(e.g., installed in trees

conduit or direct

buried) not subject

to 10 CFR 50.49

EQ requirements

(3.6.1-4)

Connector contacts Corrosion of Boric Acid None Not applicable to

for electrical connector contact Corrosion BWRs

connectors exposed surfaces due to

to borated water intrusion of borated

leakage water

(3.6.1-5)

Fuse Holders Fatigue due to. Fuse Holders None Not Consistent with

(Not Part of a Larger ohmic heating, GALL Report (See

Assembly): Fuse thermal cycling, SER

holders - metallic electrical transients, Section 3.6.2.3)

clamp frequent

(3.6.1-6) manipulation,

vibration, chemical

contamination,

corrosion, and

oxidation

Metal enclosed Loosening of bolted Metal Enclosed Bus Metal-Enclosed Bus Consistent with

bus - connections due to Inspection Program GALL Report, which

Bus/connections thermal cycling and (B.1.17) recommends no (3.6.1-7) ohmic heating further evaluation

(See SER

Section 3.6.2.1)

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Component Aging Effect/ AMP in GALL AMP in LRA Staff

Group Mechanism Report Evaluation

(GALL Report

Item No.)

Metal enclosed Reduced insulation Metal Enclosed Bus Metal-Enclosed Bus Consistent with

bus - resistance and Inspection Program GALL Report, which

Insulation/insulators electrical failure due (B.1.17) recommends no

(3.6.1-8) to various physical, further evaluation

thermal, radiolytic, (See SER

photolytic, and Section 3.6.2.1)

chemical

mechanisms

Metal enclosed Loss of material due Structures Metal-Enclosed Bus Consistent with

bus - Enclosure to general corrosion Monitoring Program Inspection Program GALL Report, which

assemblies (B.1.17) recommends no

(3.6.1-9) further evaluation

(See SER

Section 3.6.2.1)

Metal enclosed Hardening and loss Structures Metal-Enclosed Bus Consistent with

bus - Enclosure of strength due to Monitoring Program Inspection Program GALL Report, which

assemblies elastomers (B. 1.17) recommends no

(3.6.1-10) degradation further evaluation

(See SER

Section 3.6.2.1)

High voltage Degradation of A plant-specific None Consistent with

insulators insulation quality aging management GALL Report for

(3.6.1-11) due to presence of program is to be which further

any salt deposits evaluated evaluation is

and surface recommended (See

contamination; Loss SER

of material caused Section 3.6.2.2)

by mechanical wear

due to wind blowing

on transmission

conductors

Transmission Loss of material due A plant-specific None Consistent with

conductors and to wind induced aging management GALL Report for

connections; abrasion and program is to be which further

switchyard bus and fatigue; loss of evaluated evaluation is

connections conductor strength recommended (See

(3.6.1-12) due to corrosion; SER

increased Section 3.6.2.2)

resistance of

connection due to

oxidation or loss of

preload

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Component Aging Effectl AMP in GALL AMP in LRA Staff

Group Mechanism Report Evaluation

(GALL Report Item No.)

Cable Connections - Loosening of bolted Electrical Cable None Not consistent with

Metallic parts connections due to Connections Not GALL Report (See

(3.6.1-13) thermal cycling, Subject To SER Section 3.6.3)

ohmic heating, 1.0 CFR 50.49

electrical transients, Environmental

vibration, chemical Qualification

contamination, Requirements

corrosion, and

oxidation

Fuse Holders None None' None Consistent with

(Not Part of a Larger GALL Report

Assembly)

Insulation material

(3.6.1-14)

The staffs review of the electrical and instrumentation and controls component groups followed

one of several approaches. One approach, documented in SER Section 3.6.2.1, discusses the

staff's review of the AMR results for components that the applicant indicated are consistent with

the GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.6.2.2, discusses the staff's review of the AMR results for components that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.6.2.3, discusses the staff's

review of the AMR results for components that the applicant indicated are not consistent with, or

not addressed in, the GALL Report. The staff's review of AMPs that are credited to manage or

monitor aging effects of the electrical and instrumentation and controls components is

documented in SER Section 3.0.3.

3.6.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the effects of aging related to the electrical and instrumentation and

controls components:

" External Surfaces Monitoring Program

" Metal-Enclosed Bus Inspection Program

* Non-EQ Instrumentation Circuits Test Review Program

* Non-EQ Insulated Cables and Connections Program

* Oil Analysis Program

In LRA Table 3.6.2-1, the applicant provided a summary of AMRs for the electrical and

instrumentation and controls components and identified which AMRs it considered to be

consistent with the GALL Report.

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Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report does not recommend

further evaluation, the staff performed an audit and review to determine whether the

plant-specific components contained in these GALL Report component groups were bounded by

the GALL Report evaluation.

The applicant provided a note for each AMR line item. The notes describe how the information in

the tables aligns with the information in the GALL Report. The staff audited those AMRs with

notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR was

valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is consistent

with the GALL Report for material, environment, and aging effect. In addition, the AMP is

consistent with the AMP identified by the GALL Report. This note indicates that the applicant

was unable to find a listing of some system components in the GALL Report; however, the

applicant identified a different component in the GALL Report that has the same material,

environment, aging effect, and AMP as the component that was under review. The staff audited

these line items to verify consistency with the GALL Report. The staff also determined whether

the AMR line item of the different component was applicable to the component under review and

whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is consistent

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes

some exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line items

to verify consistency with the GALL Report. The staff also determined whether the identified

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and

whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA. The staff did not

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repeat its review of the matters described in the GALL Report; however, the staff did verify that

the material presented in the LRA was applicable and that the applicant identified the appropriate

GALL Report AMRs. The staff's evaluation is discussed below.

3.6.2.1.1 Loss of material due to general corrosion

In the discussion section of LRA Table 3.6.1, Item 3.6.1-9, the applicant stated that loss of

material of metal enclosed bus enclosure assemblies is managed by the Metal-Enclosed Bus

Inspection Program. The staff noted that in the AMR results line that points to Table 3.6.1,

Item 3.6.1-9, the applicant included a reference to Note E.

The staff reviewed the AMR results line referenced to Note E and determined that the component

type, material, environment, and aging effect are consistent with the corresponding line of the

GALL Report; however, where the GALL Report recommends the AMP XI.S6, "Structures

Monitoring Program," the applicant has proposed the Metal-Enclosed Bus Inspection Program.

As discussed in SER Section 3.0.3.2.13, the staff found the Metal-Enclosed Bus Inspection

Program acceptable to inspect loss of material of metal enclosed bus enclosure assemblies due

to corrosion. On this basis, the staff finds the AMR results for this line item acceptable.

3.6.2.1.2 Hardening and loss of strength due to elastomer degradation

In the discussion section of LRA Table 3.6.1, Item 3.6.1-10, the applicant stated that elastomer

degradation of metal enclosed bus enclosure assemblies is managed by the Metal-Enclosed Bus

Inspection Program. The staff noted that in the AMR results line that points to Table 3.6.1,

Item 3.6.1-9, the applicant included a reference to Note E.

The staff reviewed the AMR results line referenced to Note E and determined that the component

type, material, environment, and aging effect are consistent with the corresponding line of the

GALL Report; however, where the GALL Report recommends the AMP XI.S6, "Structures

Monitoring Program," the applicant has proposed the Metal-Enclosed Bus Inspection Program.

As discussed in SER Section 3.0.3.2.13, the staff found the Metal-Enclosed Bus Inspection

Program acceptable to inspect the metal enclosed bus elastomer degradation.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing the associated aging effects. On the basis of its review, the staff

concludes that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are indeed consistent with the AMRs in the GALL Report. 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

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical information in the Application. In LRA Section 3.6.2.2, the applicant

provided further evaluation of aging management, as recommended by the GALL Report, for the

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electrical and instrumentation and controls components. The applicant provided information

concerning how it will manage the following aging effects:

" electrical equipment subject to EQ

" degradation of insulator quality due to presence of any salt deposits and surface

contamination, and loss of material due to mechanical wear

" loss of material due to wind induced abrasion and fatigue, loss of conductor strength due

to corrosion, an increased resistance of connection due to oxidation or loss of pre-load

QA for aging management of nonsafety-related components

Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant

claimed consistency with the GALL Report and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. The

staff's evaluation of the aging effects is discussed in the following sections.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

The staff reviewed LRA Section 3.6.2.2.1 against the criteria in SRP-LR Section 3.6.2.2.1.

In LRA Section 3.6.2.2.1, the applicant stated that environmental qualification is a TLAA, as

defined in 10 CFR 54.3.

SRP-LR Section 3.6.2.2.1 states that the applicants are required to evaluate TLAAs in

accordance with 10 CFR 54.21(c)(1). The evaluation of the TLAA is addressed in SRP-LR

Section 4.4.

SER Section 4.4 documents the staff's review of the applicant's evaluation of this TLAA. Based

on the review, staff concludes that the applicant has met the criteria of SRP-LR Section 3.6.2.2.1.

3.6.2.2.2 Degradation of Insulator Quality Due to Presence of Any Salt Deposits and Surface

Contamination, and Loss of Material Due to Mechanical Wear

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2.

In LRA Section 3.6.2.2.2, the applicant addressed degradation of insulator quality due to

presence of salt deposits and surface contamination, and loss of material due to mechanical

wear. The applicant stated, in the LRA, that the insulators evaluated for JAFNPP license renewal

are those used to support uninsulated, high-voltage electrical components such as transmission

conductors and switchyard buses. Various airborne materials such as dust, salt and industrial

effluent can contaminate insulator surface. The buildup of surface contamination is gradual and in

most areas washed away by rain. The glazed insulator surface aids this contamination removal. A

large buildup of contamination enables the conductor voltage to track along the surface more

easily and can lead to insulator flashover. Surface contamination can be a problem in areas

where there are greater concentrations of airborne particles such as near facilities that discharge

soot or near the sea coast where salt spray is prevalent. JAFNPP is not located near the

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seacoast or near other sources of airborne particles. The applicant, therefore, concludes that

surface contamination is not an applicable aging effect for high-voltage insulators at JAFNPP.

The applicant also stated in the LRA that mechanical wear is an aging effect for strain and

suspension insulators subject to movement. Although this mechanism 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. Wear has not been apparent during

routine inspection and is not a credible aging effect.

SRP-LR Section 3.6.2.2.2 states that degradation of insulator quality due to presence of any salt

deposits and surface contamination could occur in high-voltage insulators. The GALL Report

recommends further evaluation of a plant-specific AMP for plants location such that the potential

exists for 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 blowing on

transmission conductors could occur in high-voltage insulators. The GALL Report recommends

further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed.

Various airborne materials such as dust, salt and industrial effluent can contaminate insulator

surface. The buildup of surface contamination is gradual and in most areas washed away by rain.

The glazed insulator surface aids this contamination removal. A large buildup of contamination

enables the conductor voltage to track along the surface more easily and can lead to insulator

flashover. Surface contamination can be a problem in areas where there are greater

concentrations of airborne particles such as near facilities that discharge soot or near the sea

coast where salt spray is prevalent. Since JAFNPP is not located near facilities that discharge

soot or near the sea coast, the staff found that surface contamination is not an applicable aging

effect requiring management for high-voltage insulators at JAFNPP.

Mechanical wear could be an aging effect for strain and suspension insulators in that they are

subject to movement. Movement of the insulators can be caused by wind blowing the supported

transmission conductor, causing it to swing from side to side. If this swinging is frequent enough,

it could cause wear in the metal contact points of the insulator string and between an insulator

and supporting hardware. Although the mechanical wear is possible, experience has shown that

transmission conductors do not normally swing and even when they do, due to a substantial wind,

do not continue to swing for long once the wind has subsided. Because transmission conductors

do not frequently swing and even when they do, due to substantial wind, do not continue to swing

for a long when the wind has subside, the staff found that the mechanical wear is not an

applicable aging effect that can cause a loss of intended function of the insulators at JAFNPP.

Therefore, an AMP for high-voltage insulators is not required.

Based on the technical justification identified above, the staff concludes that the applicant has

met the criteria of SRP-LR Section 3.6.2.2.2. For those line items that apply to LRA

Section 3.6.2.2.2, the staff determines that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.6.2.2.3 Loss of Material Due to Wind Induced Abrasion and Fatigue, Loss of Conductor

Strength Due to Corrosion, an Increased Resistance of Connection Due to Oxidation or Loss of

Pre-Load

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The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3.

In LRA Section 3.6.2.2.3, the applicant addressed loss of material due to wind induced abrasion

and fatigue, loss of conductor strength due to corrosion of transmission conductors, and

increased resistance of connections due to oxidation or loss of pre-load of transmission

connections, and in switchyard bus connections. The applicant stated, in the LRA, that

transmission conductors are uninsulated, stranded electrical cables used outside building in

high-voltage applications. The transmission conductor commodity group includes the associated

fastening hardware, but excludes the high-voltage insulators. Major active equipment assemblies

include their associated transmission conductor terminations.

The applicant also stated that transmission conductors are subject to AMR if they are necessary

for recovery of offsite power following an SBO. At JAFNPP, transmission conductors located

between the switchyard breaker and reserve station service transformer (RSST) T3 support

recovery from an SBO event. Other transmission conductors are not subject to AMR since they

do not perform a license renewal intended function. For potential loss of conductor strength due

to corrosion, the applicant stated in the LRA that the most prevalent mechanism contributing of

conductor strength of an aluminum conductor steel reinforced (ACSR) transmission conductor is

corrosion which includes corrosion of the steel core and aluminum strand pitting. There is a set

percentage of composite conductor strength established at which a transmission conductor is

replaced. Corrosion rate depends largely on air quality. Corrosion of ACsR conductors is a very

slow-acting aging effect that is even slower for rural areas with generally less suspended particle

and SO2 concentration in the air than urban areas.

For the potential loss of material due to wind induced abrasion of transmission conductors, the

applicant, in the LRA, stated that wind loading can cause transmission conductor vibration, or

sway. Consideration of wind loading is during the design and installation phase. Loss of material

that could be caused by transmission vibration or sway are not applicable aging effects in that

they would not cause a loss of intended function if left unmanaged for the extended of operation.

For the potential increased resistance of connection due to oxidation or loss of pre-load of

transmission and transmission connection, switchyard bus, and switchyard bus connections, the

applicant, in the LRA, states that the switchyard bus is uninsulated, un-enclosed, rigid electrical

conductors used in medium and high-voltage applications. Switchyard bus includes the hardware

used to secure the bus to high-voltage insulators. Switchyard bus establishes electrical

connections to disconnect switch, switchyard breakers, and transformers. Switchyard bus located

at the switchyard breakers and at RSST T2 and T3 that support recovery from an SBO event are

subject to aging management review. The staff also noted that the switchyard bus, disconnect

switch 10017 and its connections between South 115kV bus and North 115kV bus are included in

the aging management review. Other switchyard bus does not require AMR since they do not

perform a license renewal intended function. Connections surface oxidation for aluminum

switchyard bus is not applicable since switchyard bus connections requiring AMR are welded

connections. For ambient environmental condition at JAFNPP, no aging effects have been

identified that could cause a loss of intended function for the period of extended operation.

Vibration is not applicable since flexible connectors connect switchyard bus. Therefore, the

applicant concludes no aging effects requiring management for the switchyard bus.

SRP-LR Section 3.6.2.2.3 states that loss of material due to wind induced abrasion and fatigue,

loss of conductor strength due to corrosion, and increased resistance of connection due to

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oxidation or loss of pre-load could occur in transmission conductors and connections, and in

switchyard bus and connections. The GALL Report recommends further evaluation of a

plant-specific AMP to ensure that this aging effect is adequately managed.

The staff requested the applicant to explain why loss of conductor strength due to corrosion is not

an aging effect requiring management for transmission conductors at JAFNPP. The staff also

requested the applicant to include any test data to support applicant's response. In its response,

the applicant stated that:

Test performed by Ontario Hydroelectric showed a 30% loss of composite

conductor strength of an 80 year old ACSR conductor due to corrosion. RSST

71T-3 is connected to the 115kV switchyard with overhead transmission lines. The

overhead transmission conductors are 336.4 MCM ACRS 18/1 conductors with a

7AWG static- wire., This specific conductor type was bounded by the type of Ontario

Hydroelectric tests. There is a set percentage of composite conductor strength

established at which a transmission conductor is replaced. As illustrated below,

there is ample strength margin to maintain the transmission conductor intended

function through the period of extended operation.

The National Electrical Safety Code (NESC) requires that tension on installed

conductors be a maximum of 60% of the ultimate conductor strength. The NESC

also sets the maximum tension a conductor must be designed to withstand under

heavy load requirements, which includes consideration of ice, wind and

temperature. These requirements are reviewed concerning the specific conductors

included in the AMR. The strength margin (4/0 ACRS) will be used as an

illustration.

The ultimate strength and the NESC heavy load tension requirement of 4/0 (212

MCM) ACSR are 8350 lbs. and 2761 lbs., respectively. The margin between the

NESC heavy load and the ultimate strength is 5589 lbs., there is a 67% of ultimate

strength margin. The Ontario Hydroelectric study showed a 30% loss of composite

conductor strength in an 80 year old conductor. In the case of the 4/0 ACSR

transmission conductor, a 30% loss of ultimate strength would mean that there

would still be a 37% ultimate strength margin between that is required by the

NESC and the actual conductor strength.

The 4/0 ACSR conductors have the lowest initial design margin of transmission

conductors included in the AMR. This illustrates with reasonable assurance that

transmission conductors will have ample strength through the period of extended

operation. There are no applicable aging effects that could cause a loss of intended

function of the transmission conductors for the period of extended operation.

The staff found the applicant's response acceptable because corrosion of ACSR conductor is a

very slow acting mechanism and test data from Ontario Hydroelectric, which is bounded by the

types of conductors at JAFNPP, illustrates that transmission conductors will have ample strength

through the period of extended operation. Based on this information, the staff concludes that loss

of conductor strength is not a significant aging effect requiring management at JAFNPP.

In LRA, Section 3.6.2.2.3, the applicant states that "loss of material that could be caused by

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transmission conductor vibration or sway are found not to be applicable aging effects in that they

would not cause a loss of intended function if left unmanaged for the extended period of

operation." The staff requested the applicant to explain why transmission conductor vibration or

sway would not cause a loss of intended function. The applicant responded that:

Transmission conductor vibration, or sway, would be caused by wind loading.

Wind loading that can cause a transmission line and insulator to vibrate is

considered in the design and installation. Loss of material (wear) and fatigue that

could be caused by transmission conductor or sway are found not be applicable

aging effects in that they would not cause a loss of intended function if left

unmanaged for the period of extended operation. A review of industry OE 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 OE did not identify any unique aging effects for

transmission conductors.

The staff found the applicant's response acceptable because wind loading that can cause a

transmission line and insulator to vibrate is considered in the design and installation. In addition,

the applicant confirmed that no OE or staff's generic communication related to loss of material of

transmission conductors due to vibration or sway was identified. Therefore, the staff found that

loss of material caused by transmission conductor vibration or sway is not an applicable aging

effect requiring management.

In the LRA, the applicant stated that no aging effects requiring management and no AMP is

required for switchyard bus and connections. SRP, Section 3.8.2.2.3 identifies loss of preload is

an potential aging effects for switchyard bus connections. In addition, EPRI document Technical

Report TR-1 04213, "Bolted Joint Maintenance & Application Guide," recommends inspection of

bolted joints for evidence of overheating, signs of burning or discoloration, and indication of loose

bolted connections. The staff requested the applicant to provide a discussion why torque

relaxation or surface oxidation for bolted connections of switchyard bus is not a concern at

Fitzpatrick. The applicant responded that:

Connection surface oxidation and loosening of bolted connections for aluminum

switchyard bus is not applicable since the switchyard bus connections requiring

AMR are welded connections. However, the flexible conductors, which are welded

to the switchyard bus, are bolted to the other switchyard components. These

switchyard component connections are also included in the infrared preventive

maintenance of the 115kV switchyard, which verifies the effectiveness of the

connection design and installation practices. The infrared PM is performed at least

once every year. These flexible conductors were not considered part of the

switchyard bus in the application, but these flexible conductors will be added to the

switchyard bus commodity for completeness. These flexible conductor bolted

connections are assembled similar to the transmission conductor bolted

connection. These connections are also included in the annual infrared inspection

of the 115 kV switchyard, which verifies the effectiveness of the connection design

and installation practices. For environmental condition at JAFNPP, no significant

aging has been identified that could cause a loss of intended function for the

period of extended operation. Vibration is not applicable since flexible conductors

connect to active components. Although not specifically stated, the switchyard

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connection requiring AMR are welded and bolted connections. Neither of these

connections types require aging management, because the loosening of bolted

connections is not a significant aging effect.

The staff found the applicant's response acceptable because heat created by increased

resistance of switchyard bus connections due to corrosion or bolt loosening will be detected using

the annual infrared PM. This PM will maintain the integrity of switchyard bus connections.

The staff also requested the applicant to provide a discussion why torque relaxation and surface

oxidation of bolted connection of transmission conductors are not a concern for Fitzpatrick. The

applicant responded that:

Torque relaxation is not a significant aging effect for transmission connections.

The design of the transmission conductor bolted connection preclude torque

relaxation, and the plant specific OE supports this statement. The OE report did

not identify any failures of switchyard connection due to aging. The typical design

of switchyard bolted connections includes Bellville washers and is no-ox coated.

The type of bolting plate and the use of Bellville washers is the industry standard

to preclude torque relaxation. This combined with the proper sizing of the

conductors virtually eliminate the need to consider this aging mechanism,

therefore, there will be no significant aging.

The transmission conductors within the scope of license renewal at JAFNPP are

limited to the connections from the 115kV switchyard to the station service

transformer for the SBO recovery path. JAFNPP performs infrared inspection of

the 115 kV switchyard connections as part of a PM that is performed at least once

per year. This PM and the absence of plant OE confirms that non significant aging

is occurring for JAFNPP. Based on this information, torque relaxation of

transmission connections does not require aging management for JAFNPP.

Loss of material due to corrosion of connections due to surface oxidation is an

applicable aging mechanism, but is not significant enough to cause a loss of

intended function. The components in the switchyard are exposed to precipitation,

but these component do not experience any appreciable aging effects in this

environment, except for minor oxidation, which does not impact the ability of the

connection to perform their intended function. At JAFNPP, switchyard connection

surface are coated with an anti-oxidant compound (i.e., a grease-type sealant)

prior to tightening the connection to prevent the formation of oxides on the metal

surface and to prevent moisture from emerging the connections thus reducing the

chances of corrosion. Based on the operating experience, the method of

installation has been shown to provide a corrosion resistant low electrical

resistance connection. In addition, the infrared inspection of the 115 kV switchyard

verifies that this aging effect is not significant for JAFNPP. Therefore, it is

concluded that general corrosion resulting from oxidation of switchyard connection

surface metals does not require management at JAFNPP.

The staff found the applicant's response acceptable because the design of transmission

connections using Bellville washers will eliminate the potential torque relaxation of bolted

connections. Anti-oxidant compound will prevent the formation of oxides on the metal surface and

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to prevent moisture entering the connections thus reducing the chances of corrosion. In addition,

routine infrared PM is performed at least annually to detect heat created by high resistance due

to corrosion or bolted loosening and to verify the integrity of switchyard connections.

Based on the technical justification identified above, the staff concludes that the applicant has

met the criteria of SRP-LR Section 3.6.2.2.3. For those line items that apply to LRA

Section 3.6.2.2.3, the staff determines that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.6.2.2.4 Quality Assurance for-Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.

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

Summary of Technical Information in the Application. In LRA Table 3.6.2-1, the staff reviewed

additional details concerning the results of the AMRs for material, environment, AERM, and AMP

combinations that are not consistent with the GALL Report, or that are not addressed in the GALL

Report.

In LRA Table 3.6.2-1, the applicant indicated, via notes F through J, that the combination of

component type, material, environment, and AERM does not correspond to a line item in the

GALL Report. The applicant provided further information concerning how the aging effects will be

managed. Specifically, note F indicates that the material for the AMR line item component is not

evaluated in the GALL Report. Note G indicates that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicates that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicates

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are 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 discussed in the following sections.

3.6.2.3.1 Electrical Components Summary of Aging Management Evaluation -

LRA Table 3.6.1

In LRA Table 3.6.1, Item 3.6.1-6 discussion column, the applicant stated that fatigue due to

ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical

contamination, corrosion, and oxidation of fuse holders (not part of a larger assembly) metallic

clamp is not applicable to JAFNPP because a review of JAFNPP documents indicates that fuse

holders using metallic clamps are either part of an active device or located in circuits that perform

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no intended function. Therefore, the applicant states that fuse holders with metallic clamps at

JAFNPP are not subject to aging management review at JAFNPP.

On the basis that fuse holders are either part of an active assembly or located in circuits that

perform no license renewal intended function, the staff finds that an AMR is not required for fuse

holders (insulation and metallic parts) at JAFNPP. The staff also finds that for this component

type, the aging effect is not applicable to JAFNPP.

In LRA Table 3.6.1-4, the applicant states that aging effects defined in GALL Report are not

applicable to the inaccessible medium-voltage cables which are not subject to 10 CFR 50.49 EQ

requirements. The staff requested the, applicant, in a letter dated November 7, 2006, to provide

the detail explanation of how the review was conducted and the criteria used to determine that

JAFNPP has no inaccessible medium-voltage cables requiring aging management and a list of

cables considered for the review. In this letter, the staff also requested the applicant to identify if

medium-voltage cable safety-related cable such as residual heat removal service water pump is

inaccessible and provide a technical justification of why an AMP is not required.

In its response dated December 6, 2006, the applicant states that:

The cables that are susceptible to water treeing are those exposed to significant

moisture and subject to significant voltage (energized at least 25% of the time at

2kV to 35kV). In Section 2.5 of the LRA, inaccessible medium-voltage cables were

excluded from AMR based on the statement "JAFNPP does not have any

inaccessible underground medium-voltage cables that perform a license renewal

intended function."

The method used for identifying medium-voltage cables was to review the

electrical cable and raceway information system for all "H" level cables. At

JAFNPP, the "H" designation is for 2kV to 35kV insulated cables. A review of

JAFNPP drawings and cable information system identified inaccessible medium

voltage cables. The medium-voltage cables were then screened for exposure to

moisture (was the routing underground), and type of service (was the cable

energized greater than 25% of the time). The core spray pump motor cables and

the residual heat removal pump motor cables are the only inaccessible

medium-voltage cables that have a license renewal intended function, are

potentially exposed to moisture, and are energized greater than 25% of the time.

These cables are in the EQ program and therefore, are replaced based on

qualified life and are not subject to an AMR. JAFNPP has no non-EQ inaccessible

medium-voltage cables that support an intended function.

The RHR service water pump motor cable are not exposed to moisture; therefore,

they were screened out. As stated in previously, the only cables that met the

criteria for inaccessible medium-voltage cables are subject to 10 CFR 50.49 EQ

requirements. EQ cables are replaced based on qualified life, therefore, in

accordance with 10 CFR 54.21(a)(1)(ii), they are not subject to AMR.

The staff noted that cables within the scope of license renewal have to be non-EQ,

medium-voltage (2kV to 35kV), and are subjected to significant moisture (installed in duct banks,

cable trench underground) and significant voltage (energized more than 25% of the time) to be

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included in GALL AMP XI.E3 program. Because JAFNPP does not have any non-EQ inaccessible

medium-voltage cables that meet the above criteria, the staff finds that aging effects for

inaccessible medium-voltage cables identified in GALL Report are not applicable to JAFNPP.

3.6.2.3.2 Electrical 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 components.

In LRA, Table 3.6.2-1, under Cable Connections, under Note I, the applicant states that aging

effect in GALL Report for this component, material, and environment combination is not

applicable, Table 3.6.1, Item 3.6.1-13 discussion column, the applicant states that the loosening

of bolting connections due to thermal cycling, ohmic heating, electrical transients; vibration, :

chemical contamination, corrosion, and oxidation of the metallic parts of cable connections is not

applicable to JAFNPP because cable connections outside of active devices are taped or sleeved

for protection. Operating experience with metallic of electrical cable connections at JAFNPP

indicated no aging effects requiring management.

The staff noted that electrical cable connections are subject to the thermal cycling, ohmic heating,

electrical transients, vibration, chemical contamination, corrosion, and oxidation aging stressors.

GALL Report, Revision 1, AMP XI.E6, "Electrical Cable Connection not Subject to 10 CFR 50.49

Environmental Qualification Requirements," specifies that connections associated with cables

within the scope of license renewal are part of this program, regardless of their association with

active or passive components. The staff requested that the applicant provide a justification for

why an AMP is not necessary or provide an AMP with the ten elements for cable connections. In

its response, the applicant stated that:

The LR project identifies connections to include in the AMP by evaluating the

JAFNPP non-EQ cable connections that meet the criteria of being a bolted

connection. Switchyard connections are not addressed in this program, since

these connections operate at a much higher voltage (> 35kV); they are addressed

separately as part of the switchyard commodity types.

Connection for all voltage levels are considered in scope. The stressors thermal

cycling, ohmic heating, and electrical transients are potential stressors only for

high load connections.

Thermal cycling, ohmic heating, and electrical transients are not potential stressors

for low-load connections. Low-load connections located in a controlled

environment can be screened out, because vibration, chemical contamination,

corrosion and oxidation are not a concern. Low-load field instrumentation

connections within the scope of license renewal such as pressure transmitters,

resistant temperature detectors (RTDs), and flow transmitters are not subject to an

AMR, because the instrumentation within the scope of license renewal located in a

harsh environment, are typically EQ, the non-EQ sensitive instrument circuit (high

radiation and neutron monitoring) connections which are included in GALL

AMP XI.E2 program. All connections associated with circuits that do not an

intended function, such as general lighting, are not subject to an AMR.

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The types of circuits considered for identifying cable connections are electrical and

instrumentation and controls (I&C) penetrations, DC load centers, inverters,

battery chargers, motors, motor control centers (MCCs), switchgear, circuit

breakers, transformers, metal-enclosed bus, and field components. All of the

electrical and I&C penetration are EQ; therefore, all of the connection for these

penetrations were excluded. The field components considered include

current/potential transformers (CTs/PTs), and power supplies. The assumption

made for the non-EQ high load connections was that all of these connections are

bolted.

The basis discusses the stressors that are being addressed. Plant information

(single line drawing, switchyard drawing) was searched t determine the potential

population of bolted connections. The criterion used for determining the high load

connections was identifying powers circuits for all voltage levels. The types of

cable connections that were determined to meet the definition of a high load

connection are subject to an AMR.

In addition to the proposed one-time inspection program, many of the JAFNPP

cable connections are inspected or tested by preventive maintenance (PM) for the

following components were searched to determine if the PM evaluated the field

cable connections associated with the active components.

0 480 VAC MCCs and Switchgear (MP-056.01 AC Motor Control

Center Maintenance)

0 600 VAC MCCs and Switchgear (MP-056.01 AC Motor Control

Center Maintenance)

0 4160 VAC Switchgear (MP-054.02 4.16kV Bus and Metal-Clad

Switchgear)

0 AC Motors(MP-059.83 Motor Power Monitoring (MPM) Testing and

Analysis)

* DC Motors (MP-059.83 MPM Testing Analysis)

* 125 VDC Distribution and Lighting Panels (MP.200.16 Maintenance and

Subcomponent Replacement of GE 7700 Series DC Motor Control

Centers)

Battery Control Board (MP.200.16 Maintenance and Subcomponent

Replacement of GE 7700 Series DC Motor Control Centers)

125 VDC MCCs (MP.200.16 Maintenance and Subcomponent

Replacement of GE 7700 Series DC Motor Control Centers)

• Battery Chargers

* Reserve Transformers (MP-071.42 Station Service Transformer

Maintenance)

The maintenance procedures for these component types have details to detect

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degradation of bolted connections.

The maintenance rule indicators for the systems that contain these commodities

do not show problems or issues that have not been resolved. There is no plant OE

that identified degraded connections where the degradation was a result of aging.

JAFNPP will have a one-time inspection program that will inspect or test a

representative sample of the connection types. The one-time inspection program

will verify that there no aging effects that require management during the period of

extended operation.

The applicant also stated that the scope of program will include non-EQ connections associated

with cables within the scope of license renewal are included in this program. The program does

not include the higher voltage (> 35 kV) switchyard connections. The connections within the

scope of license renewal are screened for applicability of this program. This program will focus on

the metallic parts of the cable connections. The one-time inspection verifies that the loosening of

bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical

contamination, corrosion, and oxidation do not require a periodic aging management program. A

representative sample of the electrical cable connection population subject to an AMR will be

inspected and tested. The sample will include each type of electrical cable connection. The

following factors will be considered for sampling: voltage level (medium and low voltage), circuit

loading (high load), and location (high temperature, high humidity, vibration, etc.). The technical

basis for the sample selected will be documented. This is listed as the Commitment No. 24.

Pending the review of the applicant's one-time inspection program as discussed above and the

LRA supplement, the staff found the applicant's response acceptable. Many of the JAFNPP cable

connections are inspected or tested by periodic preventive maintenance. The staff reviewed a

sample of these procedures and confirmed that the cable connections associated with active

components are inspected or monitored. For low load connections located in a controlled

environment (etc, control room), vibration, chemical contamination, corrosion and oxidation are

not a concern because the above aging effects are not significant. These cable connections can

be screened out. High-voltage connections (> 35 kV) are installed in the switchyard and these

connections are addressed in SER Section 3.6.2.2. For cable connections that are not covered by

a preventive maintenance or are not located in a controlled environments, the applicant will have

a one-time inspection that will inspect or test a representative sample of the connection types.

The staff also found the one-time inspection acceptable because no plant operating experience

has identified degraded connections where the degradation was a result of aging. A

representative sample of electrical connection population subject to AMR will be inspected and

tested. The applicant will consider the following factors for sampling: voltage level (medium and

low voltage), circuit loading (high load), and location (high temperature, high humidity, vibration,

etc.). The technical basis for the sample selected will be documented.

In its letter dated February 1, 2007, the applicant added LRA Sections A.2.1.40 and B.1.34

describing its Bolted Cable Connections Program. It also amended Section 3.6.2.1, Aging Effects

Requiring Management, Section 3.6.2.1, Aging Management Program, Table 3.6.1, and

Table 3.6.2-1. The applicant also included the plant-specific program elements for Bolted Cable

Connections Program. The staff's evaluation of the applicant's Bolted Cable Connections

Program is documented in SER Section 3.0.3.3.6.

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In LRA Table 3.6.2-1, under oil filled cable system, the applicant indicated via footnote J for

material, environment, aging effects and aging management program. Footnote J is neither the

component nor the material and environment combination evaluated in GALL report. The

applicant also stated that 115kV oil-filled cables (passive electrical for station blackout) has no

aging effect requiring management for meeting the component's electrical intended function.

In RAI 3.6.2-1 dated November 7, 2006, the staff requested that the applicant provide a technical

justification of why an AMP is not required or provide a plant-specific AMP that contains the

required ten elements to manage the aging effects due to aging mechanism such as paper,

insulation degradation, moisture intrusion, elevated temperature, and galvanic corrosion. In

addition, the staff also requested the applicant to explain what periodic tests are planned prior to

and during the period of extended operation.

In its response dated April 6, 2007, the applicant stated that:

The JAFNPP AMR determined there were no aging effects requiring management for the

oil-filled cables for the "provide electrical connection" function.

The underground oil-filled cable environment is constant temperature soil, ambient

temperature, and moisture. The underground oil-filled cables are 350 MCM hollow core

copper, oil with impregnated/copper wall/intercalated with paper tape/copper bearing lead

wall and a polyethylene jacket. The underground oil-filled cables use a lead sheath to

prevent effects of moisture on the cables. This cable is designed with a thick layer of lead

over the cable insulation and an overall jacket over the lead and insulation. Lead sheath

cables are designed for submergence for extended operation.

Operating experience was reviewed by searching JAF condition reports and interviewing

knowledgeable plant staff. No failures were identified. This is consistent with the industry

operating experience for this type of cable system.

The mechanism/stressor identified in this question are not an issue for this type of cable.

A lead-sheathed cable is not susceptible to moisture intrusion. There are no environment

issues associated with degradation of the paper insulation. This is supported by plant and

industry OE. Elevated operating temperature is not an issue since the cables are

designed for the load and do not operate in an area of elevated temperature. There are no

dissimilar metal connections, so galvanic corrosion is not an issue. Since the cable is

lead-sheathed, the insulation material is protected from moisture.

The staff disagreed with the applicant's conclusion that there were no aging effects requiring

management for the oil-filled cables. The staff determined that degradation of oil-filled cable

system in a contaminated oil environment is a concern that needs to be addressed during the

period of extended operation. Based on the staff's review of vendor manual and discussions with

the cable manufacturer, the staff determined that a positive oil pressure must be maintained in

the cable system at all times to prevent any moisture intrusion, This is needed to ensure that the

dielectric property of the oil in the cable system can be maintained to the manufacturer's

specifications. The oil-filled cable system must also be inspected for oil leaks and the oil samples

should be tested in accordance with industry standards. To address the staffs concern, the

applicant revised its aging management evaluations in a letter dated April 6, 2007. The applicant

stated that:

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LRA Section 3.6.2.1, Oil-Filled Cable System, will be added as follows:

Oil-Filled Cable System

The reserve station service transformer (T2) high side connects to the 115kV

switchyard breaker (10022) via an underground low-pressure oil-filled cable.

The mechanical portion, oil-filled cable system components provide a reservoir of

oil for the cables with a high/low alarm. The mechanical portion has an intended

function of pressure boundary, which is subject to aging management review.

The electrical portion of the oil-filled cable system consists of a single 350MCM

cable per phase plus a spare cable. The 115kV underground low-pressure oil-filled

transmission cables are in the offsite-power recovery path and are subject to aging

management review.

115kV Oil-Filled Cables (electrical)

The reserve station service transformer (T2) high side connects to the 115kV

switchyard breaker (10022) via an underground low-pressure oil-filled cable.

The underground oil-filled transmission cable consists of a single 350MCM cable

per phase plus a spare cable. The spare cable is to ensure reliability is maintained

should there be a single cable failure. Cable construction has a spiral steel core as

a central helix preventing cable collapse and serves as the channel for the

cable-oil. Copper conductors are shaped over the spiral steel core. The copper

conductors are wrapped with paper insulation then completely immersed and

impregnated with insulating oil under pressure. A seamless lead sheath is applied

to the impregnated paper, which prevents moisture intrusion into the cable

insulation and retains the oil. As an anti-corrosion protection, the cable uses an

okolene (black polyethylene) outer jacket over the lead sheath. Lead sheath

cables are designed for installation in wet environments for extended periods.

The JAF oil-filled cable system will be included in the periodic surveillance and

preventive maintenance program to verify the absence of aging effects that require

management.

Underground Low-Pressure Oil-Filled Cable System (Mechanical)

The oil-filled cable system consists of carbon steel tanks, stainless steel cell

banks, sight glasses, copper alloy and stainless steel valve bodies, and stainless

steel tubing with an intended function of pressure boundary.

The cell banks, tanks, sight glasses, valve bodies, and tubing environments are oil

internal and outdoor air external.

Aging Effects for Mechanical Components

Aging effects for materials exposed to oil:

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MATERIAL

Carbon Steel

(internal surfaces)

Stainless Steel

(internal surfaces)

Copper Alloy

(internal surfaces)

AGING EFFECT

Loss of Material

Loss of Material

Loss of Material

AGING MECHANISM

General corrosion

Galvanic corrosion

Crevice corrosion

Microbiologically influenced

corrosion (MIC)

Pitting Corrosion

Crevice corrosion

Microbiologically influenced

corrosion (MIC)

Pitting Corrosion

Crevice corrosion

Microbiologically influenced

corrosion (MIC)

Pitting Corrosion

Selective leaching

Aging effects for materials exposed to air-outdoor:

MATERIAL

Carbon Steel

(external)

Stainless Steel

(external)

Copper Alloy

(external)

AGING EFFECT

Loss of Material

Loss of Material

Loss of Material

AGING MECHANISM

General corrosion

Crevice corrosion

Pitting Corrosion

Crevice corrosion

Pitting Corrosion

Crevice corrosion

Pitting Corrosion

Aoina Effects for Electrical Components

Loosening of bolted connections

Aging Effects Requiring Management

Loss of material from internal and external surfaces of carbon steel, stainless steel

and copper alloy components is an aging effect requiring management. The Oil

analysis program and External surfaces monitoring program in conjunction will be

implemented by JAFNPP to manage aging effects for the mechanical portion

oil-filled cable system.

Operating Experience Review

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The operating experience review at JAFNPP did not identify any failures of the

oil-filled cable system, but because of the uniqueness of this system, an additional

search was performed for the oil filled cable. Additional operating experience was

reviewed by searching the JAF CR database, and the INPO database for

additional keywords "oil-filled," "cable failure," "underground cable," and "115kV."

No failures were identified for the oil-filled cable. Interviews with knowledgeable

plant staff did not identify any additional OE.

JAFNPP Aging Management Programs

The Oil Analysis Program, External Surfaces Monitoring Program, and Periodic

Surveillance and Preventive Maintenance Program in combination will manage the

effects of aging, thereby precluding loss of the intended functions of the oil-filled

cable system.

Oil Analysis Program

The Oil Analysis Program will manage the mechanical portion of the low-pressure

oil-filled cable system maintaining the oil systems free of contaminants (primarily

water and particulates) thereby preserving an environment that is not conducive to

aging mechanisms. This program manages loss of material for carbon steel,

stainless steel, and copper alloy components wetted by oil. Also, this program will

test the insulating oil contained in the electrical cable portion of the system.

Insulating oil testing will be performed based on testing criteria and acceptance

criteria in accordance with Doble: Reference Book on Insulating Liquids and

Gasses, Doble Engineering company.

External Surfaces Monitoring

Under the External Surfaces Monitoring Program, visual inspections manage aging

effects for the external surfaces of the mechanical portion of the low-pressure oil

filled cable system. The program manages loss of material for external carbon

steel, stainless steel, and copper alloy components by visual inspection of external

surfaces.

Periodic Surveillance and Preventive Maintenance Program

The following activities, under the Periodic Surveillance and Preventive

Maintenance Program for the 115kV underground oil-filled cables will verify the

absence of aging effects requiring management. A preventive maintenance

procedure will provide the maintenance activities for the oil-filled cable system as

described in the vendor maintenance requirements. This program will ensure that

the oil-filled cable system will be able to perform its intended function into the

period of extended operation.

Weekly operational inspections are performed on thel 15kV yard readings to check

oil level in the reservoirs. Each reservoir is equipped with an external sight-glass

and a level switch to provide high and low-level alarms. This assures positive

pressure and purity of the oil to assure there are no voids.

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Visual inspection will be performed to:

" Check all exposed parts of the cable, potheads and reservoirs for physical

damage

* Check seams, valves, soldered joints and lead wipes for evidence of oil

leaks

0 Check oil level in the reservoir against previous level.

These visual inspections meet the vendor recommendations and will be performed

at least once per year.

A PM will be performed to check the oil level alarm switch settings in accordance

with the vendor manual: This PM will be performed at least once every year.

During maintenance inspections on circuit breakers and transformers, the following

will be performed:

* Check the torque of the pothead bolts as specified in the vendor manual.

The frequency of this maintenance will be at least once every five years.

By letter dated June 20, 2007, the applicant added the following to the Periodic Surveillance and

Preventive Maintenance Program:

A power factor or partial discharge test will be performed in accordance with

industry standards. The initial test will be completed prior to the period of extended

operation. The frequency of the test will be adjusted based on the initial test

results; the test frequency shall be at least once every ten years.

The applicant also revised LRA Table 3.6.2-1 to reflect its AMR evaluations by letters dated

April 6, 2007 and June 20, 2007.

Loss of material from internal and external surface of carbon steel, stainless steel and copper

alloy components in oil-filled cable system is an aging effect requiring management. In addition,

breakdown of insulation is also an AERM. The Oil Analysis Program, External Surfaces

Monitoring Program, and Periodic Surveillance and Preventive Maintenance Program in

combination will be implemented by the applicant to manage aging effects for the oil-filled cable

system. The staff's evaluation of these programs show that it adequately manages the aging

effect identified by the applicant. The staff's evaluation of Oil Analysis Program, External Surface

Monitoring Program, and Periodic Surveillance and Preventive Maintenance Program are

discussed in SER Sections 3.0.3.2.14, 3.0.3.2.9, and 3.0.3.3.4, respectively. In its response

dated April 6, 2007, the applicant committed to implement the Oil-Filled Cable System aging

management that will be controlled by the External Surfaces Monitoring Program, Oil Analysis

Program, and Periodic Surveillance and Preventive Maintenance Program before the period of

extended operation (Commitment No. 25 (JAFP-07-0048, dated April 6, 2007)).

The staff finds the applicant's response to RAI 3.6.2-1 acceptable because the actions discussed

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above are acceptable to manage aging effects of oil-filled cable system. The staff's concern

described in RAI 3.6.2-1 is resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving material, environment, AERMs, and AMP combinations that are 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).

3.6.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that the

effects of aging for the electrical and instrumentation and controls components, that are 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 functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the applicable 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

activities authorized by the renewed license will continue to be conducted in accordance with the

CLB, and any changes made to the CLB, in order to comply with 10 CFR 54.21(a)(3), are in

accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section of the safety evaluation report (SER) addresses the identification of time-limited

aging analyses (TLAAs). In license renewal application (LRA) Sections 4.2 through 4.7, Entergy

Nuclear Operations, Inc. (ENO or the applicant) addressed the TLAAs for James A. FitzPatrick

Nuclear Power Plant (JAFNPP). SER Sections 4.2 through 4.8 document the review of the TLAAs

conducted by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the

staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined by

the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of Federal

Regulations (10 CFR 54.21(c)(1)), applicants must list TLAAs as defined in 10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21 (c)(2), applicants must list plant-specific exemptions

granted under 10 CFR 50.12 based on TLAAs. For any such exemptions, the applicant must

evaluate and justify the continuation of the exemptions for the period of extended operation.

4.1.1 Summary of Technical Information in the Application

To identify the TLAAs, the applicant evaluated its calculations and analyses against the six

criteria specified in 10 CFR 54.3. The applicant indicated that it had searched the current

licensing basis (CLB) for calculations meeting the six criteria. The CLB includes the updated final

safety analysis report (UFSAR), engineering calculations, technical reports, engineering work

requests, licensing correspondence, and applicable vendor reports. LRA Table 4.1-1, "List of

JAFNPP TLAA and Resolution," lists the applicable TLAAs:

* reactor vessel neutron embrittlement analyses , metal fatigue analyses

" environmental qualification analyses of electrical equipment " concrete containment tendon prestress analyses

* containment liner plate, metal containment, and penetrations fatigue analyses

* recirculation valves fatigue evaluation

* leak-before-break

* BWRVIP-05, reactor pressure vessel (RPV) circumferential welds analysis

* BWRVIP-25, core plate

* BWRVIP-38, shroud support fatigue analysis

* BWRVIP-47-A, lower plenum fatigue analysis

* BWRVIP-74, reactor vessel

* BWRVIP-76, core shroud fatigue analysis

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it did not identify exemptions granted

under 10 CFR 50.12 based on a TLAA as defined in 10 CFR 54.3.

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4.1.2 Staff Evaluation

LRA Section 4.1 lists the JAFNPP TLAAs. The staff reviewed the information to determine

whether the applicant has provided sufficient information pursuant to 10 CFR 54.21(c)(1 ) and

10 CFR 54.21(c)(2).

As defined in 10 CFR 54.3, TLAAs meet the following six criteria:

(1) involve systems, structures, and components within the scope of license renewal as

described in 10 CFR 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term (40 years)

(4) are determined to be relevant by the applicant in making a safety determination

(5) involve conclusions, or provide the basis for conclusions, related to the capability of the

system, structure, and component to perform its intended functions, as described in

10 CFR 54.4(b)

(6) are contained or incorporated by reference in the CLB

The applicant listed common TLAAs from NUREG-1800, Revision 1, "Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated

September 2005. The applicant listed TLAAs applicable to JAFNPP in LRA Table 4.1-1.

The staff reviewed information in Table 4.1-1. The staff also reviewed related Class 1

components in Table 3.1.2-1. Generally, a metal fatigue analysis based on a known initial flaw

should also be performed for those components that contain flaw(s) and is performed to assess

the stability of the final crack size of the affected component at the end of the license. This

analysis will demonstrate that the component has sufficient fracture toughness to resist rapid

crack propagation and thus arrest the crack. The method for this calculation would follow the

ASME Code Section Xl. The LRA discussed this analysis without providing much detail.

In RAI 3.1.2-1 dated April 2, 2007, the staff requested that the applicant discuss the number of

years assumed in the associated fatigue crack growth analysis, and to discuss whether the

affected components are demonstrated to be acceptable for the period of extended operation.

In the applicant's response to RAI 3.1.2-1 dated April 24, 2007, the applicant indicated particular

flaw and mechanic fracture evaluations as potential TLAAs for the LRA under 10 CFR 54.3 TLAA

criteria. The staff reviewed these flaw and fracture evaluations against the 10 CFR 54.3 TLAA

definition criteria to determine whether they should have been indicated as TLAAs for the LRA.

The staff's assessment of these flaw and fracture evaluations is in SER Section 4.7.4.

As required by 10 CFR 54.21(c)(2), the applicant must list all exemptions granted under

10 CFR 50.12, based on TLAAs, and evaluated and justified for continuation through the period

of extended operation. The LRA states that each active exemption was reviewed to determine

whether it was based on a TLAA. The applicant did not identify any TLAA-based exemptions.

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Based on the information provided by the applicant regarding the process used to identify these

exemptions and its results, the staff concludes, in accordance with 10 CFR 54.21(c)(2), that the

applicant identified no TLAA-based exemptions justified for continuation through the period of

extended operation.

4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable list of

TLAAs, as required by 10 CFR 54.21(c)(1). The staff confirmed, as required by

10 CFR 54.21(c)(2), that no exemption to 10 CFR 50.12 had been granted based on a TLAA.

4.2 Reactor Vessel Neutron Embrittlement

The regulations governing reactor vessel, integrity are in 10 CFR Part 50. Section 50.60 of

10 CFR requires that all light-water reactors meet the fracture toughness, pressure-temperature

(P-T) limits, and material surveillance program requirements for the reactor coolant pressure

boundary as set forth in 10 CFR Part 50, Appendices G and H. The JAFNPP CLB analyses

evaluating reduction of fracture toughness of the reactor vessel-for 40 years are TLAA. The

reactor vessel neutron embrittlement TLAA has been projected to the end of the period of

extended operation as summarized below. Because the reactor has not been operated at its

effective full-power (EFPY), the fifty-four EFPYs are thus projected for the end of the period of

extended operation (60 years) based on an average capacity factor of 90 percent.

4.2.1 Reactor Vessel Fluence

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 summarizes the evaluation of reactor vessel fluence for the period of extended

operation. The applicant initially provided the GE-NE-B1 100732-01 report to support its

evaluation; however, this report was found by the staff to be not conforming to Regulatory Guide

(RG) 1.190, "Calculational and dosimetry methods for Determining Pressure Vessel Neutron

Fluence," and thus, this item was identified as Open Item (01) 4.2.1-1 in the SER With Open

Items issued on July 31, 2007.

4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.2.1, and the applicant's response to 01 4.2.1-1 dated

November 5, 2007, pursuant to 10 CFR 54.21 (c)(1). Specifically, the staff reviewed the

methodology, benchmarking and uncertainties, and the fluence values for the elements in the

vessel belt region.

MethodoloQy. The RAMA code performs a series of transport calculations based on

reactor, core, and vessel geometry, nuclear data from the BUGLE-96 cross-section library

and reactor operating history. The outputs include fluxes, fluence, wire activation and

uncertainties. The RAMA neutron transport calculations are deterministic in three

dimensions using an integration scheme equivalent to S8. The minimum inelastic

scattering approximation is equivalent to P5. As stated above, the RAMA code has been

reviewed by the staff, has been found to adhere to the guidance in RG 1.190, and has

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been approved for use in licensing actions.

Benchmarkinq and Uncertainties. The approved RAMA methodology has been

benchmarked for application to the Fitzpatrick plant. A set of three copper (Cu), iron (Fe),

and nickel (Ni) dosimeter wires were exposed for the first six operating cycles at the

30 'azimuthal angle. The dosimeter location within the surveillance capsule was not

exactly known but was calculated at the center of the capsule, which is the usual location

of dosimeter wires. The results showed remarkable agreement with the measured values,

which indicates that the location was correct and that the prediction was excellent.

Another set of two dosimeter wires of Cu, Fe, and Ni were irradiated for 12 cycles (at the

120 °azimuthal angle) and were also analyzed. The assumed location was also the

capsule center and the results were very good indicating that the location was correct and

that the agreement was very good. Additional comparisons of measured and calculated

dosimetry were reported. The staff finds that the reported results were in excellent

agreement. Uncertainty calculations were performed as prescribed in RG 1.190. The

overall uncertainty is 12.1 percent (1), well within the required uncertainty limits of ± 20

percent (1 o).

The fluence values were calculated using an approved and benchmarked code (RAMA)

for FitzPatrick. Section 7 of the report lists detailed fluence values for all the elements of

the vessel beltline region. The staff finds that the values are acceptable because the

RAMA code adheres to the guidance in RG 1.190, and the RAMA code has been

approved and benchmarked.

The staff also determined that the new calculated neutron fluence has also been accounted for

the 5 percent power uprate implemented at the start of operating cycle 13 in November 1998.

The fluence values at the end of the extended license are conservatively assumed to correspond

to 54 EFPYs of operation. The calculations provide information for all the beltline elements (i.e.,

plates and welds) to 54 EFPY at the inside diameter, 1/4-thickness and 3/4-thickness locations

derived from RG 1.99 formulae. There are no nozzles in the beltline region for the current term of

operation. Re-evaluation of the beltline for 60 calender years is based on the axial flux profile in

the active fuel and nozzle elevations. Fluence at the recirculation inlet nozzles will not exceed 1.0

x 1017 n/cm2 (E greater than 1.0 MeV) during the period of extended operation. Based on the

above evaluation, the staff concludes that the reactor vessel fluence TLAA complies with the

10 CFR 54.21 (c)(1)(ii) acceptance criterion for TLAAs.

4.2.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

reactor vessel fluence in LRA Section A.2.2. 1.1. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant's actions to

address reactor vessel fluence is adequate.

4.2.1.4 Conclusion

The staff reviewed and accepted the applicant's new methodology (submitted as Amendment 14

by letter dated November 5, 2007) that was used for calculating the neutron fluence values. The

staff's acceptability is based on its finding that applicant's new methodology has now been

4-4
adhered to the guidance in RG 1. 190, which has been approved by the staff. Therefore, the staff

concludes that the reactor vessel fluence TLAA complies with the 10 CFR 54.21(c)(1)(ii)

acceptance criterion for TLAAs. The staff also determines that the UFSAR supplement contains

an appropriate summary description of the TLAA for the reactor vessel fluence for the period of

extended operation, as required by 10 CFR 54.21(d). Based on this, the staff concludes that the

previously identified sOl 4.2.1-1 as described in the SER With Open Items issued on

July 31, 2007, is now closed.

4.2.2 Pressure-Temperature Limits

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2 summarizes the evaluation of P-T limits for the period of extended operation.

The adjusted reference temperature (ART) is a key material property for the development of

operating P-T limits. The ART is the sum of the initial reference temperature (nil-ductility

transition) (RTNDT), ARTNDT, and margins for uncertainties at a specific reactor vessel location.

Neutron embrittlement increases the ART value, thus increasing the minimum metal temperature

at which a reactor vessel is allowed to be pressurized. The ART value for the limiting beltline

material determines the beltline P-T limits to account for irradiation effects. Part 50 of 10 CFR,

Appendix G, requires operating P-T limits for three categories of operation: (1) hydrostatic

pressure and leak tests, (2) non-nuclear heatup and cooldown operations, including low-level

reactor physics tests, and (3) core critical operations. Since the calculations of P-T limits satisfy

10 CFR 54.3(a) criteria, this topic is a TLAA. These limits are established by calculations that

utilize the materials and fluence data from the Reactor Vessel Surveillance Program.

Technical specifications (TS) have P-T limits valid through 32 EFPY. The fact that the projected

maximum RTNDT is well below the 200 OF suggested in RG1.99, Section 3, gives confidence that

P-T curves will provide an acceptable operating area through 54 EFPY. The Boiling Water

Reactor Vessel and Internals Project (BWRVIP) Integrated Surveillance Program (BWRVIP

Reports 86-A, 102, 116 and 135), as approved by the NRC, will be used to adjust projected RTNDT

values as additional surveillance capsule results are collected. The applicant will submit additional

P-T curves for staff review and approval in accordance with 10 CFR Part 50, Appendix G, prior to

the expiration of the P-T limit curves for the current licensing term.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the

updated P-T limits for the period of extended operation must be available prior to entering the

period of extended operation.

The staff's review of P-T limits was based on the applicant's fluence values provided in LRA

Section 4.2.1. However, the calculation methodology for the reactor vessel fluence values, as

was originally submitted, did not conform to Regulatory Guide 1.190. Thus the review of this

TLAA was identified as sub Open item (sOl) 4.2.2-1 in the SER With Open Items issued on July

31, 2007. As described in SER Section 4.2.1.2, the staff reviewed and accepted the applicant's

new methodology (submitted as Amendment 14 by letter dated November 5, 2007) that was used

for calculating the neutron fluence values. The staff found that the newly calculated neutron

fluence values remain bounded by the values that were submitted in the applicant's original LRA.

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Therefore, the projected ART values of the lower shell and the lower intermediate shell of the

RPV remain valid. Based on this, the staff concludes that the previously identified sub-Open Item

(sOl) 4.2.2-1 as described in the SER With Open Items issued on July.31, 2007, is now closed.

The applicant's Table 4.2-3 shows the projected 54 EFPY fluence and ART values for the period

of extended operation. The staff finds that the projected 54 EFPY fluence and ART values are in

fact less than the 200 OF suggested in RG 1.99, Section 3.

The staff's review of LRA Section 4.2.2 found areas in which additional information was

necessary to completed the review of the applicant's TLAA evaluation. The applicant responded

to the staff's requests for additional information (RAIs) as discussed below.

In RAI 4.2.2-1 dated January 12, 2007, the staff asked the applicant to clarify whether the 54

EFPY P-T limit curve bases summarized in LRA Table 4.2-3 take into account power uprate

conditions.

In its responses dated February 12, 2007, the applicant stated:

The RTNDT values projected in LRA Table 4.2-3 are based on calculated fluence

values of 0.17 x 1019 n/cm2 (E > 1 MeV) for the lower shell and 0.21 x 1019 n/cm 2

(E > 1 MeV) for the lower intermediate shell. These fluence values included the

uprate to 2536 Megawatts thermal at the end of Cycle 12.

In RAI 4.2.2-2, dated January 12, 2007, the staff asked the applicant when it intended to submit

P-T limit curves for the period of extended operation (54 EFPY). This request followed the

requirement that P-T limits for the period of extended operation must be approved by the staff in

accordance with 10 CFR Part 50, Appendix G, prior to the expiration of the P-T limit curves for

the current licensing term.

In its response dated February 12, 2007, the applicant stated:

In accordance with 10 CFR Part 50.59 (c)(2), Part 50.60, and Appendix G,

JAFNPP will submit P-T curves for use past 32 EFPY prior to reaching 32 EFPY.

The staff finds the applicant's plan to manage the P-T limits acceptable because (1) the projected

54 EFPY fluence and ART values are in fact less than the 200 OF suggested in RG 1.99,

Section 3, and (2) changes to the P-T limit curves will be implemented by the license amendment

process (i.e., through revisions of the plant TS) in accordance with 10 CFR 50.60 and

10 CFR Part 50, Appendix G. Therefore, the staff concludes that the applicant's plan to manage

P-T limits complies with the 10 CFR 54.21(c)(1)(iii) acceptance criterion for TLAAs as

recommended in Section 4.2.2.1.3.3 of the SRP-LR.

4.2.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of P-T

limits in LRA Section A.2.2.1.2.

LRA Section A.2.2.1.2 includes the following UFSAR supplement summary description of the

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TLAA for the JAFNPP P-T limits:

The P-T limits were derived from calculations made in accordance with the

guidance of ASME Appendix G, as modified by Code Cases N-588 and N-640,

ASTM Standards, 10 CFR 50 Appendices G and H, Regulatory Guide 1.99

Revision 2, and Generic Letter 88-11.

Pressure-temperature limits are valid through 32 EFPY. The fact that the projected

maximum RTNDT is well below the 200°F suggested in Section 3 of Regulatory

Guide 1.99, gives confidence that P-T curves will provide acceptable operating

area through 54 EFPY. The BWRVIP Integrated Surveillance Program (BWRVIP

Reports 86-A, 102, 116 and 135) will be used to adjust projected RTNDT values

as additional surveillance capsule results are collected. JAFNPP will submit

additional: P-T curves prior to the period of extended operation.

The applicant's UFSAR Supplement summary description of the TLAA for the P-T limits

appropriately describes how the applicant will determine the P-T limits for the period of extended

operation for JAFNPP.

On the basis of its review of the UFSAR supplement, the staff concludes that the summary

description of the applicant's actions to address P-T limits is adequate.

4.2.2.4 Conclusion

The staff reviewed the applicant's TLAA for the P-T limits, as summarized in LRA Section 4.2.2,

including RAI responses dated February 12, 2007, and determined that the TLAA for P-T limits is

acceptable because (1) the projected 54 EFPY fluence and ART values are in fact less than the

200 °F suggested in RG 1.99, Section 3, and (2) changes to the P-T limit curves will be

implemented by the license amendment process (i.e., through revisions of the plant TS) in

accordance with 10 CFR 50.60 and 10 CFR Part 50, Appendix G. Therefore, the staff concludes

that the applicant's plan to manage P-T limits complies with the 10 CFR 54.21(c)(1)(iii)

acceptance criterion for TLAAs as recommended in Section 4.2.2.1.3.3 of the SRP-LR. The staff

therefore concludes that safety margins established and maintained during the current operating

license term will be maintained during the period of extended operation as required by

10 CFR 54.21(c)(1). The staff concludes that the previously identified sol 4.2.2-1 as described in

the SER With Open Items issued on July 31, 2007, is now closed because the staff accepted the

applicant's new methodology (submitted as Amendment 14 by letter dated November 5, 2007) for

the reactor fluence values calculation and found the projected ART values of the lower shell and

the lower intermediate shell of the RPV remain valid. The staff also concludes that the UFSAR

supplement contains an appropriate summary description of the TLAA for the P-T limits for the

period of extended operation, as required by 10 CFR 54.21(d).

4.2.3 Charpy Upper-Shelf Energy

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 summarizes the evaluation of Charpy Upper-Shelf Energy (CVUSE) for the

period of extended operation. Appendix G of 10 CFR Part 50 requires reactor vessel beltline

4-7
materials to "have Charpy upper shelf energy ... of no less than 75 ft-lb initially and must maintain

Charpy upper-shelf energy throughout the life of the vessel of no less than 50 ft-lb." The initial

(unirradiated) USE values for JAFNPP beltline materials were provided in correspondence

responding to Generic Letter (GL) 92-01 and are now included in Reactor Vessel Integrity

Database 2 and BWRVIP-135. RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel

Materials," provides two methods for determining CvUSE. Position 1 applies for material without

surveillance data and Position 2 for material with at least two sets of surveillance data. The

applicant has two surveillance data sets from the reactor vessel plate material showing changes

in CvUSE; however, as the observed changes are less than the RG 1.99 projected changes,

Position 1 is used and conservatively does not reduce the projections based on surveillance data.

For Position 1, the percentage drop in CvUSE for a stated copper content and neutron fluence is

determined by reference to Figure 2 of RG 1.99, Revision 2. This percentage, drop applied to the

initial cvUSE obtains the adjusted CvUSE.

The reactor vessel plates are projected to remain above 50 ft-lb; consequently, no equivalent

margin analysis is required for the plates. However, no initial CvUSE is available for the reactor

vessel weld material, so the decrease from the original value cannot be calculated, and an

equivalent margin analysis must be done. The applicant updated the originally submitted

equivalent margin analyses for plates and welds to include the second surveillance capsule data.

The results show that the reduction in CvUSE calculated for the plates and welds remains less

than the limiting reduction calculated in BWRVIP-74-A and acceptable for the period of extended

operation. All equivalent margin analyses for reactor vessel welds show CVUSE reductions less

than those of BWRVIP-74-A and all CvUSE TLAAs extrapolated through the period of extended

operation are acceptable. These TLAAs have been projected to the end of the period of extended

operation.

4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.2.3, to verify pursuant to 10 CFR 54.21(c)(1 )(ii), that the

analyses have been projected to the end of the period of extended operation.

Section IV.A.1 of 10 CFR Part 50, Appendix G, requires reactor vessel beltline materials to have

CvUSE values greater than or equal to 50 ft-lb (68 J) throughout a facility's operating license

period unless lower CvUSE values can be demonstrated, in a manner approved by the Director,

Office of Nuclear Reactor Regulation, to ensure margins of safety against fracture equivalent to

those required by American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel

Code (ASME Code) Section XI, Appendix G.

On September 21, 1999, the BWRVIP submitted Topical Report TR-1 113596, "BWRVIP-74:

BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw

Evaluation Guidelines for License Renewal" (BWRVIP-74). BWRVIP-74, Appendix B, assessed

the license renewal actions needed to demonstrate that plant-specific equivalent margin analyses

(EMAs) on USE would be acceptable for periods of extended operation. The staff issued its final

SER (FSER) on BWRVIP-74 on October 18, 2001. In this FSER, the staff established the

following position on acceptance of TLAAs on USE/EMA:

Section IV.A.la. of Appendix G to 10 CFR Part 50 requires, in part, that RPV

beltline materials shall have Charpy USE in the transverse direction for base metal

4-8
and along the weld for weld material of no less than 50 ft-lb (68J), unless it is

demonstrated in a manner approved by the Director, Office of Nuclear Reactor

Regulation, that lower values of Charpy USE will provide margins of safety against

fracture equivalent to those required by Appendix G of Section XI of the ASME

Code.

By letter dated April 30, 1993, the Boiling Water Reactor Owner's Group

(BWROG) submitted a topical report entitled '10 CFR 50 Appendix G Equivalent

Margins Analysis for Low Upper Shelf Energy in BWRI2 Through BWR/6 Vessels,'

to document that BWR RPVs could meet the margins of safety against fracture

equivalent to those required by Appendix G of the ASME Code for Charpy USE

values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concluded

that the topical report demonstrated that the materials evaluated had the margins

of safety against fracture equivalent to Appendix G of the ASME Code, in

accordance with Appendix G of 10 CFR Part 50. In this report, the BWROG

derived through statistical analysis the initial USE values for materials that

originally did not have documented Charpy USE values. Using these statistically

derived Charpy USE values, the BWROG predicted the end-of life (40 years of

operation) USE values in accordance with RG 1.99, Revision 2 (RG 1.99, Rev. 2).

According to this RG, the decrease in USE is dependent upon the amount of

copper in the material and the neutron fluence predicted for the material. The

BWROG analysis determined that the minimum allowable Charpy USE in the

transverse direction for base metal and along the weld for weld metal was 35 ft-lb.

Appendix B in the BWRVIP-74 report provides a bounding Charpy USE for BWR

plants for 54 EFPY. The BWRVIP-74 analysis utilized an unirradiated Charpy USE

in the longitudinal direction of 91 ft-lb for BWR/3-6 plates and 70.5 ft-lb for

non-Linde 80 submerged arc welds. The value for the plates is the lowest value

from the database and is less than the lower 95/95 confidence value. The value for

the non-Linde 80 submerged arc welds is the value corresponding to the lower

95/95 confidence value. Since these values are statistically determined with at

least 95/95 confidence, these values may be used in the evaluation of Charpy

USE.

The analysis in the BWRVIP-74 report determined the reduction in the unirradiated

Charpy USE resulting from neutron radiation using the methodology in RG 1.99,

Rev. 2. Using this methodology and using a correction factor of 65-percent for

conversion of the longitudinal properties to transverse properties, the lowest

irradiated Charpy USE at 54 EFPY for all BWR/3-6 plates is projected to be 45

ft-lb. The correction factor for specimen orientation in plates is based on NRC

Branch Technical position MTEB 5-2. Using the RG methodology the lowest

irradiated Charpy USE at 54 EFPY for BWR non-Linde 80 submerged arc welds is

projected to be 43 ft-lb. The BWRVIP-74 report indicates that the percent

reduction in Charpy USE for the limiting BWR/3-6 plates and BWR non-Linde 80

submerged arc welds are 23.5 percent and 39 percent, respectively. To

demonstrate that the beltline materials meet the criteria specified in the report, the

applicant shall demonstrate that the percent reduction in Charpy USE for their

beltline materials are less than those specified for the limiting BWR/3-6 plates and

the non-Linde 80 submerged arc welds and that the percent reduction in Charpy

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USE for their surveillance weld and plate are less than or equal to the values

projected using the methodology in RG 1.99, Revision 2. This is Renewal

Applicant Action Item 10.

Section IV.A.1.a of 10 CFR Part 50, Appendix G, requires reactor vessel beltline materials to

have CvUSE values of no less than 50 ft-lb in the transverse direction for base metal and along

the weld for weld material unless lower CvUSE values can be demonstrated, in a manner

approved by the Director, Office of Nuclear Reactor Regulation, to ensure margins of safety

against fracture equivalent to those required by ASME Code Section XI, Appendix G.

According to RG 1.99, Revision 2, the predicted decrease in USE due to neutron embrittlement

during plant operation depends upon the amount of copper in the material and its predicted

neutron fluence. RG 1.99, Revision 2, Position 1, specifies methods for calculating the predicted

decrease in USE for materials without sufficient credible surveillance data available. The staff

confirmed that the initial USE values were based appropriately on the applicant's previous

response to GL 92-01. The applicant appropriately determined the predicted end of life (EOL)

USE values for the reactor vessel beltline materials for the period of extended operation by

applying the predicted percentage decrease in USE from RG 1.99, Revision 2, to the initial USE

values.

The staffs review of USE values was based on the applicant's fluence values in LRA

Section 4.2.1. As described in SER Section 4.2.1.2, the staff reviewed and accepted the

applicant's new methodology (submitted as Amendment 14 by letter dated November 5, 2007)

that was used for calculating the neutron fluence values. The staff found that the newly calculated

neutron fluence values remain bounded by the values that were submitted in the applicant's

original LRA. Therefore, the USE values for the limiting beltline materials (i.e., lower intermediate

shell with a heat No. C3368-1 and the circumferential weld with a heat No. 1-240) remain valid.

Based on this, the staff concludes that the previously identified sOl 4.2.3-1, is resolved and is

now closed.

The applicant submitted plant-specific information in LRA Table 4.2-1 to demonstrate that all

reactor vessel beltline materials meet 10 CFR Part 50, Appendix G, USE requirements through

the end of the period of extended operation.

In RAI 4.2.3-1 dated January 12, 2007, the staff referred to LRA Table 4.2-1 and asked the

applicant to clarify whether any other surveillance capsule data was available and, if so, to

address how the data affects the response to RAI 4.2.2-1.

In its response dated February 12, 2007, the applicant stated:

JAFNPP has withdrawn and analyzed two surveillance capsules

(GE-NE-B1 100732-01, Revision 1, February, 1998, Plant Fitzpatrick RPV

Surveillance materials Testing and Analysis of 120' Capsule at 13.4 EFPY).

With regards to the reactor vessel plate material, this has provided two data sets

showing the changes in CvUSE and RTNDT. However, as the observed changes are

less than the Regulatory Guide 1.99 projected changes, this report has used

Regulatory Guide 1.99 Position 1 and conservatively not reduced the projections

based on surveillance data.

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With regards to the reactor vessel weld material, there are no surveillance data

sets. This is because the initial CvUSE and RTNDT for the weld material are not

known, and consequently the decrease from the original value cannot be

calculated. Consequently, this report has also used Regulatory Guide .1.99

Position 1 for the weld material evaluations.

The two capsules were withdrawn at 5.98 EFPY (1985) and 13.4 EFPY (1996).

Both were withdrawn prior to the power uprate. However, the fluence projections to

32 EFPY based on these capsules was adjusted to account for the power uprate.

So there is no adjustment to the answer to RAI 4.2.2-1.

Based on its review, the staff finds the applicant has provided the needed clarification regarding

whether any other surveillance capsule data was available and it has addressed how the data

affects the applicant's previous response to RAI 4.2.2-1. The staff find the applicant's response to

RAI 4.2.3-1 acceptable and the staffs concern in RAI 4.2.3-1 is resolved.

The staff determined that the applicant correctly used RG 1.99, Revision 2, Position 1, for

conservative calculation of the predicted percentage decrease in USE for the period of extended

operation. The staff also independently calculated EOL USE values for the beltline plate materials

at 54 EFPY and EMAs of the percent drop in USE for the beltline weld materials through 54

EFPY. The staff verified the reduction in the USE values from neutron irradiation using the

methodology in RG 1.99, Revision 2, and finds that all the beltline materials meet 10 CFR

Part 50, Appendix G, EOL USE or EMA requirements and the staff's criteria in SRP-LR

Section 4.2.3.1.1.2 for accepting USE/EMA TLAAs in accordance with 10 CFR 54.21(c)(1)(ii).

Table 4.2.3.2-1 summarizes the results of both the applicant's and the staff's independent

USE/EMA calculations for the limiting plate and weld materials for USE.

Table 4.2.3.2-1 Results of Applicant's and the Staffs Independent Upper-Shelf

Energy/Equivalent Margin Analysis Calculations for the Limiting Plate and Weld Materials

for Upper-Shelf Energy (based on the new calculated neutron fluence values)

JAFNPP Reactor End Of Life Upper-Shelf End Of Life Evaluation Result

Vessel Material Energy for Limiting Materials Upper-Shelf Energy

Acceptance Criterion

Applicant. Staff

Limiting Plate 57.3 ft-lb 57.3 ft-lb USE Requirements in Acceptable per

Heat C3368-1 10 CFR Part 50, 10 CFR 54.21 (c)(1)(ii)

Appendix G

USE must be

> 50 ft-lb

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Limiting Weld 31.4% Drop in 29.6% Drop in EMA Requirements in Acceptable per

1-240 USE USE 10 CFR Part 50, 10 CFR 54.21(c)(1)(ii)

Appendix G

and the Generic

BWRVIP-74A EMA

Criteria for RPV SAW

Welds made from

Non-Linde 80 Flux

Materials -

Percent drop in USE

must be < 39%

4.2.3.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

CvUSE in LRA Section A.2.2.1.3.

The predictions for percent drop in CvUSE at 54 EFPY are based on chemistry

data and unirradiated CvUSE data submitted to the NRC in the JAFNPP response

to GL 92 01, and 1/4 T fluence values.

The 54 EFPY CvUSE values were calculated using Regulatory Guide 1.99,

Position 1, Figure 2; specifically, the formula for the lines was used to calculate the

percent drop in CvUSE.

All CVUSE values are predicted to remain well above the requirement of 50 ft-lbs

during the period of extended operation. As such, this TLAA has been projected to

the end of the period of extended operation in accordance with

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

The applicant's UFSAR supplement summary description is consistent with the staff analysis for

the TLAA of the USE in SER Section 4.2.3.2. The UFSAR supplement summary description

summarizes the applicable USE requirements that must be met for continued compliance with

10 CFR Part 50, Appendix G, during the period of extended operation. The staff therefore finds

the UFSAR supplement summary description for the TLAA of the USE acceptable. On the basis

of its review of the UFSAR supplement, the staff concludes that the summary description of the

applicant's actions to address CvUSE is adequate.

4.2.3.4 Conclusion

The staff reviewed the applicant's TLAA of the USE, as summarized in LRA Section 4.2.3,

including RAI responses dated February 12, 2007, and determines that the reactor vessel beltline

materials will continue to comply with 10 CFR Part 50, Appendix G, USE requirements throughout

the period of extended operation. The staff therefore concludes that the applicant's TLAA for the

USE complies with the 10 CFR 54.21(c)(1)(ii) acceptance criterion for TLAAs and that the safety

margins established and maintained during the current operating term will be maintained during

the period of extended operation as required by 10 CFR 54.21(c)(1).

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On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that, for CvUSE, the analyses 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). Based on this, the staff concludes that the previously identified

sOl 4.2.3-1 as described in the SER With Open Items issued on July 31, 2007, is now closed.

4.2.4 Adjusted Reference Temperature

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the evaluation of ART for the period of extended operation.

Irradiation by high-energy neutrons raises the RTNDT value for the reactor vessel. Testing of

unirradiated material specimens determines the initial RTNDT. The shift in reference temperature,

ARTNDT, is the difference in the 30 ft-lb index temperatures from the average Charpy curves

measured before and after irradiation. The ART is defined as initial RTNDT + ARTNDT + margin.

RG 1.99, Revision 2, defines the calculation for ARTNDT, margin, and ART. The P-T curves are

developed from the ART value for the vessel materials. The applicant projected values for ARTNDT

and ART at 54 EFPY using the methodology of RG 1.99 Position 1. LRA Table 4.2-3 shows the

projected ART values calculated from the chemistry data, margin values, initial RTNDT values, and

chemistry factors (CFs) in the applicant's response to GL 92-01. The new ARTNDT values were

calculated by multiplying the CF and the fluence factor for each plate and weld. Calculated

margins and the initial RTNDT added to the calculated ARTNDT arrived at the new ART value. All

projected ART values are well below the 200 OF suggested in RG 1.99 Section 3 (for 1/4

thickness) and acceptable for the period of extended operation. The ART TLAA is thus projected

through the period of extended operation.

4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.2.4, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The 1/4T RTNDT values for the reactor vessel beltline materials are inputs to the P-T limit curve

calculations required by 10 CFR Part 50, Appendix G, for operating reactors. These 1/4 RTNOT

values are in accordance with the recommended methodology of RG 1.99, Revision 2, "Radiation

Embrittlement of Reactor Vessel Materials," May 1988, accessible through the NRC Agencywide

Documents and Access Management Systems (ADAMS) at Accession No. ML003740284.

The 10 CFR Part 50, Appendix G, fracture toughness requirements (including requirements for

USE and for P-T limits) apply to all "ferritic materials of pressure-retaining components of the

reactor coolant pressure boundary of light-water reactors to provide adequate margins of safety

during any condition of normal operation, including anticipated operational occurrences and

system hydrostatic tests, to which the pressure boundary may be subjected over its service life."

The Rule requires that USE and RTNDT values calculated in accordance with the Rule's

requirements must account for the effects of neutron radiation, including the impacts of

implementation of the plant's reactor vessel surveillance program in accordance with

10 CFR Part 50, Appendix H. For ferritic components in the reactor coolant pressure boundary

(RCPB), the changes in fracture toughness properties from neutron radiation are bounded by

4-13
those in the ferritic materials located in the reactor vessel beltline region.

The staff independently calculated the 1/4T RTNDT values for the reactor vessel beltline materials

through 54 EFPY, applying the calculation methods of RG 1.99, Revision 2, and the 1/4T neutron

fluences for materials as the bases for its independent calculations. The fluence table of LRA

Section 4.2.1 lists these fluences for 54 EFPY of power operation. The staffs basis for

acceptance of the applicant's 1/4T neutron fluences for 54 EFPY is in SER Section 4.2.1.2.

The staff also determined that the BWRVIP's integrated surveillance program (ISP) applies in

monitoring changes in fracture toughness for the reactor vessel; however, as the ISP surveillance

materials, which represent the reactor vessel limiting materials, are not heat-to-heat matches,

calculations of changes in RTNDT do not use the ISP surveillance capsule test materials directly.

The staff, therefore, determined that to apply the RG 1.99, Revision 2, CF tables as the bases for

determination of the CF values in the 1/4T RTNDT calculations was appropriate. This application is

consistent with the recommended methodology of RG 1.99, Revision 2, Position 1.1.

The staffs review of ART values was based on the applicant's fluence values in LRA

Section 4.2.1. As described in SER Section 4.2.1.2, the staff reviewed and accepted the

applicant's new methodology (submitted as Amendment 14 by letter dated November 5, 2007)

that was used for calculating the neutron fluence values. The staff found that the newly calculated

neutron fluence values remain bounded by the values that were submitted in the applicant's

original LRA. Therefore, the ART values of the limiting beltline materials remain valid.

The staff confirmed that lower shell axial welds 2-233 A, B, and C fabricated from Heat

No. 27204/12008 were the limiting 1/4T RTNDT components in the reactor vessel. The staff

calculated a limiting 1/4T RTNDT value of 123.5 OF for this plate material as based on use of the

CF table for plate/forging materials in RG 1.99, Revision 2, and a 1/4T fluence 0.148 x 10" n/cm2

(E > 1.0 MeV) at 54 EFPY. The ART value calculated by the staff at 54 EFPY-is the same as the

ART value calculated by the applicant for this material. As the staffs independent 1/4T RTNDT

value is in excellent agreement with the value calculated by the applicant, the staff found that the

applicant had calculated and projected a valid limiting 1/4T RTNDT value for the reactor vessel at

54 EFPY and that the TLAA on ART values for the reactor vessel through 54 EFPY is acceptable,

as evaluated in accordance with the 10 CFR 54.21(c)(1 )(ii) criterion. Based on this, the staff

concludes that the previously identified sOl 4.2.4-1 as described in the SER With Open Items

issued on July 31, 2007, is now closed.

4.2.4.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of ART

in LRA Section A.2.2.1.4.

JAFNPP has projected values for RTNDT and adjusted reference temperature

(ART) at 54 EFPY using the methodology of Regulatory Guide 1.99. These values

were calculated using the chemistry data, margin values, initial RTNoT values, and

chemistry factors (CFs) contained in the JAFNPP response to GL 92-01 and other

licensing correspondence. New fluence factors (FFs) were calculated using the

expression in Regulatory Guide 1.99, Revision 2, Equation 2 using 54 EFPY

fluence values.

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The RTNoT TLAA has been projected through the period of extended operation,

with acceptable results, in accordance with 10 CFR 54.21(c)(1)(ii).

The staff concludes that the applicant correctly used the staff-approved methods of

RG 1.99, Revision 2 for calculating projected 54 EFPY ART values for the reactor vessel beltline

materials. The applicant's UFSAR supplement summary description is consistent with the staff

analysis for the TLAA of the ART in SER Section 4.2.4.2. Based on this assessment, the staff

finds that the UFSAR supplement summary description for the TLAA of the ART calculations

acceptable.

On the basis of its review of the UFSAR supplement, the staff concludes that the summary

description of the applicant's actions to address ART is adequate.

4.2.4.4 Conclusion

The staff reviewed the applicant's TLAA of the ART calculations, as summarized in

LRA Section 4.2.4, and determines that the applicant's calculations of the ART values for the

reactor vessel beltline materials, as projected through the period of extended operation, conform

to the recommended guidelines of RG 1.99, Revision 2. The staff, therefore, concludes that the

applicant's TLAA for the ART calculations complies with the 10 CFR 54.21(c)(1)(ii) acceptance

criterion for TLAAs and that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by

10 CFR 54.21(c)(1). The staff also concludes that the UFSAR supplement contains an

appropriate summary description of the TLAA of the ART calculations for the period of extended

operation, as required by 10 CFR 54.21(d).

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that, for ART, the analyses 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). Based on this, the staff concludes that the previously identified

sol 4.2.4-1 as described in the SER With Open Items issued on July 31, 2007, is now closed.

4.2.5 Reactor Vessel Circumferential Weld Inspection Relief

4.2.5.1 Summary of Technical Information in the Application

LRA Section 4.2.5 summarizes the evaluation of reactor vessel circumferential weld inspection

relief for the period of extended operation. Relief from reactor vessel circumferential weld

examination requirements under BWRVIP-05 is for an acceptable probability of failure per reactor

operating year based on reactor vessel metallurgical conditions as well as flaw indication sizes

and frequencies of occurrence expected at the end of a licensed operating period. The applicant

received NRC approval for this relief for the third inservice inspection interval after evaluating the

welds to the end of the current operating license (32 EFPY). The changes in metallurgical

conditions expected over the period of extended operation require additional evaluation for 54

EFPY. The relief request shows that the reactor vessel parameters after 32 EFPY were within the

NRC 32 EFPY bounding Combustion Engineering Owners Group vessel parameters from the

BWRVIP-05 SER and a conditional probability of failure for circumferential welds lower than that

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stated in the BWRVIP-05 final SER.

The staff evaluation of BWRVIP-05 utilized the FAVOR code for a probabilistic fracture

mechanics (PFM) analysis to estimate the reactor vessel shell weld failure probabilities. Three

key assumptions of the PFM analysis were (1) the neutron fluence was the estimated

end-of-license mean fluence, (2) the chemistry values were mean values based on vessel types,

and (3) the potential for beyond-design-basis events was considered. LRA Table 4.2-4 compares

the reactor vessel limiting circumferential weld parameters to those in the staff evaluation of

BWRVIP-05 for the first two key assumptions. The data in the second column (CEOG/32 EFPY)

is from SER Table 2.6-4 for BWRVIP-05. The data in the third column (JAFNPP/32 EFPY) is from

the SER for JAFNPP Relief Request 17. The data in the fourth column (CEOG/64 EFPY) is from

Table 2.6-5 of the final safety evaluation of the BWRVIP-05 Report. The data in the last column is

the projected 54 EFPY data for JAFNPP taken from Table LRA 4.2-3. (Consistent with earlier

submissions, this table uses surface fluence rather than 1/4 T fluence without margin for RTNDT,

so the resulting change in RTNDT differs from that shown in Table 4.2-3.)

The'applicant's RPV circumferential weld parameters at 54 EFPY will remain within the NRC (64

EFPY) bounding CEOG parameters from the BWRVIP-05 SER. Although a conditional failure

probability has not been calculated, the fact that the values projected to the end of the period of

extended operation are less than the 64 EFPY value leads to the conclusions that the RPV

conditional failure probability is bounded by the NRC analysis and that the conditional probability

of failure for circumferential welds remains below that stated in the BWRVIP-05 final SER.

Therefore, this analysis has been projected through the period of extended operation. The

procedures and training used to limit cold over-pressure events will be the same as those

approved when the applicant requested approval of the BWRVIP-05 technical alternative for the

current license term.

The applicant states that the procedures and training for limiting cold over-pressure events will be

the same as those approved when it requested approval of the BWRVIP-05 technical alternative

for the current license term.

4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 4.2.5, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation. The staff's review

consisted of the following:

Inservice Inspection Requirements. Inservice inspection (ISI) of ASME Code Classes 1, 2, and 3

components is in accordance with ASME Code Section XI and applicable addenda as required by

10 CFR 50.55a(g) except where specific relief has been granted pursuant to 10 CFR

50.55a(g)(6)(i). Section 50.55a(a)(3) of 10 CFR states that alternatives to the requirements of

paragraph (g) may be used, when authorized, if (i) the proposed alternatives would provide an

acceptable level of quality and safety or (ii) compliance with the specified requirements would

result in hardship or unusual difficulty without a compensating increase in the level of quality and

safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Classes 1, 2, and 3 components (including

supports) must meet the requirements except the design and access provisions and the

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pre-service examination requirements of ASME Code Section Xl, "Rules for Inservice Inspection

of Nuclear Power Plant Components," to the extent practical within the limitations of design,

geometry, and materials of component construction. The regulations require that component ISIs

and system pressure tests conducted during the first and subsequent ten-year intervals comply

with the requirements in the latest edition and addenda of ASME Code Section XI incorporated by

reference in 10 CFR 50.55a(b) twelve months prior to the start of the 120-month interval subject

to the limitations and modifications listed therein.

Augmented ISI Requirements for Reactor Vessel Shell Welds. Section 50.55a(g)(6)(ii)(A)(2) of

10 CFR requires applicants to augment their reactor vessel examinations by implementing, as

part of the ISI interval in effect on September 8, 1992, the examination requirements for reactor

vessel shell welds specified in ASME Code Section XI, Item B1.10, Table IWB-2500-1,

Examination Category B-A, "Pressure Retaining Welds in Reactor Vessel." ASME Code

Section XI, Item B1.10, includes the volumetric examination requirements forboth circumferential

reactor vessel shell welds, as specified in ASME Code Section XI, Item B1.11, and longitudinal

reactor vessel shell welds, as specified in ASME Code Section XI, Item B1.12.

Section 50.55a(g)(6)(ii)(A)(2) of 10 CFR defines "essentially 100% examination" as covering 90

percent or more of the examination volume of each weld.

Additional Regulatory Guidance on the NRC Safety Evaluation (SE) of the BWRVIP-05 Report. In

a letter dated September 28, 1995, as supplemented by letters dated June 24 and

October 29, 1996, May 16, June 4, June 13, and December 18, 1997, and January 13, 1998, the

BWRVIP, a technical committee of the BWR Owners Group (BWROG), submitted the proprietary

report, "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Shell Weld Inspection

Recommendations (BWRVIP-05)." The BWRVIP-05 Report evaluates the current inspection

requirements for BWR reactor vessel shell welds, formulates recommendations for alternative

inspection requirements, and provides a technical basis for these recommended alternative

inspection requirements. As modified, BWRVIP-05 proposed to reduce the scope of inspection of

BWR reactor vessel welds from essentially 100 percent of all reactor vessel shell welds to

examination of 100 percent of the axial welds and essentially zero percent of the circumferential

reactor vessel shell welds except for locations where the axial and circumferential welds intersect.

In addition, the report includes proposed alternatives to ASME Code requirements for successive

and additional examinations of circumferential welds, as provided in ASME Cod Section Xl,

paragraphs IWB-2420 and IWB-2430, respectively.

In the BWRVIP-05 Report, the BWRVIP committee concluded that the conditional probabilities of

failure for BWR reactor vessel circumferential welds are orders of magnitude lower than those of

the axial welds. As a part of its review of the report, the staff independently assessed the

probabilistic fracture mechanics of the results presented in the BWRVIP-05 Report. The staff's

assessment conservatively calculated the conditional probability of failure values for reactor

vessel axial and circumferential welds during the initial (current) 40-year license period and at

conditions approximating an 80-year vessel lifetime for a BWR nuclear plant. The failure

frequency is calculated as the product of the frequency for the critical (limiting) transient event

and the conditional probability of failure for the weld. The staff determined the conditional

probability of failure for axial and circumferential welds in BWR vessels fabricated by Chicago

Bridge and Iron (CB&I), Combustion Engineering Owners Group (CEOG), and Babcock and

Wilcox (B&W). The determination designated a cold overpressure event that occurred in a foreign

reactor as the limiting event for BWR reactor vessels and used the pressure and temperature

from this event in the PFM calculations. The staff estimated that the probability for the occurrence

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of the limiting overpressurization transient was lx 10-3 per reactor year.

On July 28, 1998, the staff issued its FSER on BWRVIP-05. This evaluation concluded that the

failure frequency of reactor vessel circumferential welds in BWRs was sufficiently low to justify

elimination of ISI of these welds and found the BWRVIP proposals on successive and additional

examinations of circumferential welds acceptable. The evaluation indicated that the

circumferential welds will be examined if axial weld examinations reveal any active degradation

mechanism. For each of the vessel fabricators, FSER Table 2.6-4 dated March 7, 2000, shows

the conditional failure probabilities for plant-specific conditions with the highest projected mean

ART for each weld type proposed by the respective fabricator (i.e., mean RTNDT calculations for

each of the CB&I, CEOG, and B&W limiting axial weld and limiting circumferential weld case

studies) through the expiration of the initial 40-year license period (i.e., 32 EFPY) for a

BWR-designed nuclear power plant using an 80-percent capacity factor. FSER Table 2.6-5 dated

July 28, 1998, shows the conditional failure probabilities for plant-specific conditions with the

highest projected mean RTNDT calculations for each of these case studies through the expiration

of an 80-year license period, which constitutes the licensing basis of two 20-year periods of

extended operation granted for a BWR-designed nuclear power plant using an 80-percent

capacity factor (i.e., through.64 EFPY).

The staff amended this FSER in a supplemental FSER to the BWRVIP in a letter to Carl Terry,

BWRVIP Chairman, dated March 7, 2000. In this supplemental FSER, the staff updated the

interim probabilistic failure frequencies for reactor vessel axial shell welds and revised FSER

Table 2.6-4 to correct a typographical error in the 32 EFPY mean RTNDT value cited for the limiting

CB&I case study for circumferential welds. The correction changed the 32 EFPY CF for the CB&I

case study from 109.5 0F to 134.90 F.

Additional Requlatory Guidance in NRC Generic Letter 98-05. On November 10, 1998, the NRC

issued GL 98-05, "Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to Request

Relief from Augmented Examination Requirements on Reactor Pressure Vessel Circumferential

Welds," which states that BWR applicants may request permanent (i.e., for the remaining term of

operation under the initial license) relief from 10 CFR 50.55a(g) ISI requirements for the

volumetric examination of circumferential RPV welds (ASME Code Section XI, Table IWB-2500-1,

Examination Category B-A, Item No. B1.11, "Circumferential Shell Welds") by demonstrating the

following safety criteria:

" At the expiration of the operating license, the applicants demonstrate that limiting

probability of failure for their limiting reactor vessel circumferential welds will continue to

satisfy (i.e., be less than) the limiting conditional failure probability for circumferential weld

assessed in the applicable BWRVIP-05 limiting case study.

" Applicants implement operator training and establish procedures that limit the frequency

of cold overpressure events to that specified in the staff FSER of July 28, 1998.

In GL 98-05, the staff stated that applicants applying the BWRVIP-05 criteria must continue the

volumetric inspections of all axialrreactor vessel shell welds required by ASME Code Section XI,

Table IWB-2500-1, Inspection Category B-A, Item B1.12, and the augmented volumetric

inspections of the reactor vessel axial shell welds required under 10 CFR 50.55a(g)(6)(ii)(A)(2).

For plants currently operating in accordance with their initial 40-year operating licenses, the

limiting case studies are in revised FSER Table 2.6-4 dated March 7, 2000, covering

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BWRVIP-05. For plants granted operating licenses to operate for an period of extended

operation, the limiting case studies are in FSER Table 2.6-5 dated July 28, 1998.

Additional Regulatory Guidance in the NRC SER on Topical Report BWRVIP-74 Applicable to

BWR Industry Relief Requests on Reactor Vessel Circumferential Weld Examinations. On

September 21, 1999, the BWRVIP submitted Topical Report TR-1 113596, "BWRVIP-74: BWR

Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation

Guidelines for License Renewal." In Section A.4.5 of this topical report, the BWRVIP assessed

what applicants for renewal must do in these TLAAs to support 60-year relief requests on the

circumferential weld examinations after issuance of renewed operating licenses. The staff issued

its SER on BWRVIP-74 on October 18, 2001, stating that applicants requesting renewal of BWR

operating licenses must meet the following conditions for the TLAA on reactor vessel

circumferential weld-relief requests:

" At the expiration of the renewed period, the mean RTNDT values for their reactor vessel

circumferential welds would satisfy the limiting conditional failure probability for

circumferential welds stated in the staff FSER dated June 28, 1998, as amended by the

staff FSER dated March 7, 2000.

" Applicants implement operator training and establish procedures that limit the frequency

of cold overpressure events to that specified in the staff FSER on the BWRVIP-05 Report.

The staff identified these conditions as Renewal Applicant Action Item 11. In the staff FSER on

BWRVIP-74, the staff also stated that BWR applicants could propose the following alternative to

meeting Renewal Applicant Action Item 11:

A plant-specific assessment of the probability of vessel failure at the end of the renewal

period consistent with the analytical approach in the staff FSER on BWRVIP-05, including

any subsequent revisions, and based on the chemistry of the limiting circumferential weld

and predicted neutron fluence at the end of the period of extended operation. The

assessment should demonstrate a calculated probability of failure less than or equal to

that stated in Appendix E of the staff FSER on BWRVIP-05 and should be submitted for

inspection relief.

The technical basis for relief from ASME Code Section XI circumferential weld ISI requirements is

described in the staff FSER on the BWRVIP-05 Report enclosed in a July 28, 1998, letter from

Mr. G.C. Lanais, NRC, to Mr. C. Terry, the BWRVIP Chairman. In this letter, the staff concluded

that, because the failure frequency for circumferential welds in BWR plants is significantly below

the criterion specified in RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal

Shock Safety Analysis Reports for Pressurized Water Reactors," and below the core damage

frequency (CDF) of any BWR plant, the continued inspection would decrease an already

acceptably low reactor vessel failure probability negligibly, justifying elimination of the ISI

requirements for reactor vessel circumferential welds. The staff letter indicated that BWR

applicants may request relief from 10 CFR 50.55a(g) ISI requirements for volumetric examination

of circumferential RPV welds by demonstrating that (1) at the expiration of the license, the

circumferential welds satisfy the limiting conditional failure probability for circumferential welds in

the staff's July 28, 1998 evaluation, and (2) the applicants have implemented operator training

and established procedures that limit the frequency of cold over-pressure events to that specified

in the staff SER. The letter indicated that the requirements for inspection of reactor vessel

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circumferential welds during an additional 20-year license renewal period would be reassessed

plant by plant on any BWR LRA. Therefore, the applicant must request relief from the ISI

requirements for volumetric examination of circumferential welds for the period of extended

operation in accordance with 10 CFR 50.55a(g).

In accordance with 10 CFR 50.55a(g), the staff requires that a request for relief from ASME Code

Section XI circumferential shell weld examination requirements be submitted for the period of

extended operation.

In RAI 4.2.5-1 dated January 12, 2007, the staff asked the applicant when it would apply for relief

from ASME Code Section XI circumferential weld examination requirements for the period of

extended operation.

In its response dated February 12, 2007, the applicant stated that it will submit a prior reactor

vessel circumferential weld relief request for each 10-year ISI interval in the period of extended

operation.

Based on its review, the staff finds the applicant's response to RAI 4.2.5-1 acceptable. The staffs

concern described in RAI 4.2.5-1 is resolved.

BWRVIP-74 Report Section A.4.5 indicates that the staff SER on the BWRVIP-05 Report

conservatively evaluated the BWR reactor vessels to 64 EFPY, 10 EFPY greater than what is

realistically expected for the end of the license renewal period. The staff used the mean RTNDT

value to evaluate the failure probability of BWR circumferential welds at 32 and 64 EFPY in the

staff SER on the BWRVIP-05 Report dated July 28, 1998. In this evaluation the staff used the

neutron fluence at the reactor vessel inner diameter clad-weld interface.

The staffs review of mean RTNDT values was based on the applicant's fluence values in LRA

Section 4.2.1. As described in SER Section 4.2.1.2, the staff reviewed and accepted the

applicant's new methodology (submitted as Amendment 14 by letter dated November 5, 2007)

that was used for calculating the neutron fluence values. The staff found that the newly calculated

neutron fluence values remain bounded by the values that were submitted in the applicant's

original LRA. Therefore, the mean RTNDT value of the limiting reactor vessel circumferential

weld with a heat No. 1-240 remains valid. Based on this, the staff concludes that the previously

identified sOl 4.2.5-1 is resolved and is now closed.

The staff independently calculated the mean RTNDT values (using new neutron fluence values) for

the limiting reactor vessel circumferential weld through 54 EFPY. SER Table 4.2.5-1 summarizes

the mean RTNDT value calculated by the staff for the reactor vessel through 54 EFPY and

compares the staffs mean RTNDT value to both the corresponding mean RTNDT value calculated

by the applicant and the mean RTNoT value criterion for the limiting CEOG case study at

64 EFPY.

The results in SER Table 4.2.5-1 on the following page demonstrate that the mean RTNDT value

calculated by the applicant for the reactor vessel circumferential weld is less than that for the

limiting CEOG case study and agrees with that calculated by the staff. Based on this analysis, the

staff concludes that the applicant has provided a valid basis for the conclusion that the conditional

probability of failure for the reactor vessel circumferential weld is sufficiently low to accept the

TLAA and set the basis for a relief request to eliminate the reactor vessel circumferential weld

4-20
examinations for the period of extended of operation after renewal of the operating license.

Based on this independent assessment, the staff concludes that the applicant's TLAA on

circumferential weld relief requests conforms to Renewal Applicant Action No. 11 on Topical

Report BWRVIP-74-A, has been projected to 54 EFPY, and is acceptable pursuant to

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

Table 4.2.5-1 Comparison of NRC and JAFNPP 54 EFPY Mean RTNDT Calculations to the

64 EFPY Mean RTNoT Calculations for the Limiting Combustion Engineering Owners Group

Case Study on BWRVIP-05

Limiting NRC 54 EFPY Applicant 54 EFPY

Case Study . Calculations for Calculation's for

______ __ " JAFNPP (Note 1) JAFNPP (Note 1)

Alloy % Cu 0.183 0.337 0.337

Alloy % Ni 0.704 0.609 0.609

RTNDT(u) (

0F) 0 -50 -50

Fluence 0.4 0.253 0.253

(1019 n/cm2,

E > 1.0 MeV)

Chemistry Factor 172.2 209.1 209.1

ARTNOT (TF) 128.5 132.8 131.1

Mean RTN-T (TF) 128.5 82.8 81.1

NRC Established Conditional 4.38 x 10"4 Mean RTNDT is Lower Mean RTNDT is Lower

Probability of Failure (Maximum P(F/E) than Case Study Mean than Case Study Mean

[P(F/E) ] Criterion for Case / Result value to justify RTNDT: Criterion is met. RTNDT: Criterion is met.

for Plant Specific Calculation relief: Refer to (Note 2) (Note 2)

Note 2)

Notes: (1) For the reactor vessel, the limiting circumferential weld materials determined by the

staff were equivalent to those determined by the applicant. The limiting reactor vessel

circumferential weld is 1-240 fabricated from weld heat No. 305414.

(2) If the plant-specific mean RTNDT is less than the mean RTNDr of the limiting case study,

the staff concludes that probability of failure for the plant-specific circumferential weld

under review will be less than the conditional probability of failure for the limiting

circumferential weld in the limiting case study. BWR plants that meet this criterion may

conclude that the probability of failure for the limiting circumferential reactor vessel welds

is sufficiently low to justify elimination of both volumetric examinations required by ASME

Code Section XI (Examination Category B-A, Item B.1.11) and augmented volumetric

examinations for the circumferential welds required by 10 CFR 50.55a(g)(6)(ii)(A)(2).

In the SER on BWRVIP-05 dated July 28, 1998, the staff also concluded that examination of the

reactor vessel circumferential shell welds would be required if the corresponding volumetric

examinations of the reactor vessel axial shell welds revealed any age-related degradation

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mechanism.

In RAI 4.2.5-2 dated January 12, 2007, the staff asked the applicant to confirm whether previous

volumetric examinations of the reactor vessel axial shell welds showed any indication of cracking

or other age-related degradation mechanisms.

In its response dated February 12, 2007, the applicant stated that no unacceptable inservice

examination indications have been found on reactor vessel welds (circumferential or axial).

Based on its review, the staff finds the applicant's response to RAI 4.2.5-2 acceptable. The staffs

concern described in RAI 4.2.5-2 is resolved.

The BWRVIP-05 Report uses no margin term for calculations of surface mean RTNDT for reactor

vessel circumferential welds.

In RAI 4.2.5-3 dated January 12, 2007, the staff asked the applicant to clarify the inclusion of a

margin term in LRA Table 4.2-4 and in LRA Section 4.2.5.

In its response dated February 12, 2006, the applicant stated:

Note that all the margin entries in Tables 4.2-4 and 4.2-5 are zero, and are

therefore consistent with the BWRVIP-05 SER. The margin line in Tables 4.2-4

and 4.2-5 were intended to show that the margin called for by RG 1.99 when

calculating RTNDT are set to zero here, clearly showing why these RTNDT values are

different from the RG 1.99 compliant values calculated in Table 4.2-3.

Based on its review, the staff finds the applicant's response to RAI 4.2.5-3 acceptable. The staff's

concern described in RAI 4.2.5-3 is resolved.

The applicant states that the procedures and training for limiting cold over-pressure events will be

the same as those approved when it requested relief from reactor vessel circumferential weld

examination requirements for the current license period in accordance with BWRVIP-05.

The staff finds the applicant's evaluation for this TLAA acceptable because its 54 EFPY

conditional failure probability for the reactor vessel circumferential welds is bounded by the

analysis in the staff SER dated July 28, 1998, and because the applicant will use procedures and

training for limiting cold over-pressure events during the period of extended operation.

This analysis satisfies the evaluation requirements of the staff SER dated July 28, 1998;

however, the applicant still must request relief for the circumferential weld examination for the

period of extended operation in accordance with 10 CFR 50.55a.

4.2.5.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

reactor vessel circumferential weld inspection relief in LRA Section A.2.2.1.5:

Relief from reactor vessel circumferential weld examination requirements under

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Generic Letter 98-05 is based on assessments indicating an acceptable probability

of failure per reactor operating year. The analysis is based on reactor vessel

metallurgical conditions as well as flaw indication sizes and frequencies of

occurrence that are expected at the end of a licensed operating period.

JAFNPP received NRC approval for this relief for the remainder of the original

40-year license term. The basis for this relief request is an analysis that satisfied

the limiting conditional failure probability for the circumferential welds at the

expiration of the current license, based on the NRC SERs for BWRVIP-05 and

BWRVIP-74 and the extent of neutron embrittlement.

The JAFNPP reactor pressure vessel circumferential weld parameters at 54 EFPY

will remain within the NRC's (64 EFPY) bounding CEOG parameters from the

BWRVIP-05 SER. Although a conditional failure probability has not been

calculated, the fact that the JAFNPP values at the end of license are less than the

64 EFPY value provided by the NRC leads to the conclusion that the JAFNPP RPV

conditional failure probability is bounded by the NRC analysis. As such, the

conditional probability of failure for circumferential welds remains below that stated

in the NRC's Final Safety Evaluation of BWRVIP-05. Therefore, this analysis has

been projected through the period of extended operation per 10 CFR 54.21

(c)(1)(ii).

The applicant's UFSAR supplement summary description for the TLAA of the reactor vessel

circumferential weld examination relief explains appropriately how the conditional failure

probability for the reactor vessel circumferential welds is bounded by the analysis in the staff SER

dated July 28, 1998. The applicant's UFSAR supplement summary description is consistent with

the staff analysis for the TLAA of the reactor vessel circumferential weld examination relief in

SER Section 4.2.5.2. Based on this assessment, the staff finds the UFSAR supplement summary

description for the TLAA of the reactor vessel circumferential weld examination relief acceptable.

On the basis of its review of the UFSAR supplement, the staff concludes that the summary

description of the applicant's actions to address reactor vessel circumferential weld inspection

relief is adequate.

4.2.5.4 Conclusion

The staff reviewed the applicant's TLAA of the reactor vessel circumferential weld examination

relief, as summarized in LRA Section 4.2.5, including RAI responses dated February 12, 2007.

The staff determines that the applicant appropriately described how the conditional failure

probability for the reactor vessel circumferential welds are bounded by the analysis in the staff

SER dated July 28, 1998, on the BWRVIP-05 Report and how procedures and training will limit

cold over-pressure events during the period of extended operation. The staff, therefore,

concludes that the applicant's TLAA Section 4.2.5 and UFSAR supplement A.2.2.1.5 for reactor

vessel circumferential weld examination relief will comply with the 10 CFR 54.21(c)(1)(ii)

acceptance criterion for TLAAs.

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1 )(ii), that, for reactor vessel circumferential weld

4-23
inspection relief, the analyses 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). Based on this, the

staff concludes that the previously identified. sOl 4.2.5-1 as described in the SER With Open

Items issued on July 31, 2007, is now closed.

4.2.6 Reactor Vessel Axial Weld Failure Probability

4.2.6.1 Summary of Technical Information in the Application

LRA Section 4.2.6 summarizes the evaluation of reactor vessel axial weld failure probability for

the period of extended operation. The BWRVIP recommendations for inspection of reactor vessel

shell welds (BWRVIP-05) are, based on generic analyses supporting an SER conclusion that the

generic-plant axial weld failure rate is no more than 5 x 106 per reactor year. BWRVIP-05 shows

that this axial weld failure rate is orders of magnitude greater than the 40-year end-of-life

circumferential weld failure probability and uses this analysis to justify relief from inspection of the

circumferential welds.

LRA Table 4.2-5 compares the reactor vessel limiting axial weld parameters to those in the staff

analysis. The data in the second column (CEOG 32 EFPY) is from Table 2.6-4 of the staff SER

on BWRVIP-05. The data in the third column is based on the projected 32 EFPY fluence and the

limiting weld chemistry. The data in the fourth column is from Table 2.6-5 of the staff SER on

BWRVIP-05. The data in the last column is the projected 54 EFPY data taken from LRA

Table 4.2-3. (For consistency with Columns 2 and 3, the EOL mean RTNDT is calculated without

margin and hence is lower than the LRA Table 4.2-3 RTNDT value.) The limiting axial weld

parameters are within the limits of the values assumed in the BWRVIP-05 supplemental SER

analysis and the 64 EFPY limits and values from Table 2.6-5 of that SER. As such, this TLAA has

been projected to the end of the period of extended operation.

4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 4.2.6, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation. The staff review

consisted of the following:

ISI Requirements, NRC Criteria on the BWRVIP-05 Report, and GL 98-05 Criteria. The

regulatory bases for the TLAA on reactor vessel Axial Weld Failure Analyses are in the following

subsections of SER Section 4.2.5.2:

" ISI Requirements

° Augmented ISI Requirements for Reactor Vessel Shell Welds

* Additional Regulatory Guidance in the SE of the BWRVIP-05 Report

" Additional Regulatory Guidance in Generic Letter 98-05

" Additional Regulatory Guidance in the SER on Topical Report BWRVIP-74 as Applicable

to BWR Industry RV Axial Weld Probability for Failure Analyses

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In BWRVIP Section A.4.5, the BWRVIP assessed what applicants for renewal must do in these

TLAAs to support submission of 60-year relief requests for circumferential weld examinations

after issuance of renewed operating licenses. The staff issued its FSER on BWRVIP-74 on

October 18, 2001. In this FSER, the staff assessed the impact of LRAs on reactor vessel axial

weld probability of failure analyses:

The BWRVIP-74 report does not indicate the impact of neutron embrittlement on

BWR axially-oriented RPV welds. However, in its July 28, 1998, letter to Carl

Terry, the staff identified a concern about the failure frequency of axially-oriented

welds in BWR RPVs. In a response to this concern, the BWRVIP provided

evaluations of axial weld failure frequency in letters dated December 15, 1998 and

November 12, 1999. The staffs evaluation of these analyses is contained in a

March 7, 2000, letter to Carl Terry. The FSER enclosed in that letter states that the

RPV failure frequency due to failure of the limiting axial welds in the BWR fleet at

the end of 40 years of operation is below 5 x 108 per reactor year, given the

assumptions on flaw density, distribution and location, as described in the FSER.

Since the results apply only for the initial 40-year license period of BWR plants, LR

applicants shall provide plant-specific information applicable to 60 years of

operation.

The BWRVIP identified Clinton and Pilgrim as the reactor vessels with the highest

mean RTNDT in the BWR fleet. The staff confirmed this conclusion by comparing

the information contained in the BWRVIP analysis and the information contained in

the reactor vessel integrity database (RVID) for all BWR RPV axial welds. The

staff performed analyses of the Clinton and Pilgrim plants. The results from the

staff calculations are provided in Table 1. The staff calculations used the basic

input information for Pilgrim, with three different assumptions for the initial RTNDT.

The calculations of the actual Pilgrim condition used the docketed initial RTNDT of

-48 OF and a mean RTNDT of 68 OF. A second calculation, listed as "Mod 1" in

Table 1, is consistent with the BWRVIP calculations, with an initial RTNDT of 0 OF

and a mean RTNDT of 116 °F. A third calculation, with an initial RTNDT of -2 OF and a

mean RTNDT of 114 OF, was performed to identify the mean RTNDT value required to

provide a result which closely matches the RPV failure frequency of 5 x 10' per

reactor-year.

Table 1: Comparison of Results from Staff and BWRVIP

RV Probability of

Initial Mean Failure Values

Plant RTNDT RTNDT (Vessel Failure

( 0F) (

0 F) Freq.)

Staff BWRVIP

Clinton -30 91 2.73 E -6 1.52 E -6

Pilgrim -48 68 2.24 E 77

Mod 1* 0 116 5.511E-6 1.55E-6

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[Mod2-* -2 114 5.02E-6 ,

* A variant of Pilgrim input data, with initial RTNDT - 0 OF.

** A variant of Pilgrim input data, with initial RTNDT = -2 OF

As indicated in the March 7, 2000, letter, an applicant shall monitor the axial

beltline weld embrittlement. One acceptable method is to determine the mean

RTNDT of the limiting axial beltline weld at the end of the extended period of

operation is less than the values specified in Table 1. This is Renewal Applicant

Action Item 12.

The staff FSER on BWRVIP-74 states that applicants applying for license renewal of BWR

facilities should demonstrate how they satisfy Renewal Applicant Action Item 12. As stated in the

quoted NRC position, one acceptable method demonstrates that the mean RTNDT value for the

limiting reactor vessel axial beltline weld at the end of the period of extended operation is less

than one of the corresponding values specified in Table 1.

In its letter to Mr. C. Terry, the BWRVIP Chairman dated July 28, 1998, the staff stated a concern

about the failure frequency of axial welds in BWR reactor vessels.

In its response dated December 15, 1998 and November 12, 1999, the BWRVIP evaluated axial

weld failure frequency. The staff's BWRVIP-05 supplemental SER on these evaluations is

enclosed in a letter from Mr. J. Strosnider (NRC) to Mr. C. Terry (BWRVIP) dated March 7, 2000.

The staff's generic analysis used Pilgrim Nuclear Power Station as a model for BWR-4 reactor

vessels and demonstrated that a mean RTNDT of 114 0 F resulted in a vessel failure frequency of 5

x 10- per reactor-year of operation. The applicant calculated, and the staff confirmed, that the

limiting axial weld mean RTNDT value at 54 EFPY is 97.2 0F, which supports the conclusion that

the reactor vessel failure frequency will be less than 5 x 10-6 per reactor-year of operation at the

end of the period of extended operation; therefore, this analysis is acceptable.

The staff's'supplemental SER on BWRVIP-05 established that calculation of the mean RTNDT

values for a probability of failure is as the sum of the unirradiated ART for the reactor vessel

beltline material and the shift in ART value induced by neutron irradiation (i.e., mean RTNDT =

RTNDT(U) + ARTNDT) and that a margin term uncertainty allowance is not part of the calculation. The

staff independently calculated the mean RTNDT values for the reactor vessel beltline axial welds in

accordance with this position.

Table 4.2.6-1 shows the results of the staff's independent calculations and compares the mean

RTNDT values calculated by the applicant and the "Mod 2" case study for BWR reactor vessel axial

welds. The table also shows the staff's conclusions on whether the vessel failure frequency

analysis results for the reactor vessel axial welds are acceptable and the staff's bases for these

conclusions.

The staff's independent mean RTNDT value calculations for the reactor vessel beltline axial welds,

as summarized in Table 4.2.6-1, are lower than the limiting mean RTNDT values for the Pilgrim

"Mod 2" case studies and therefore demonstrate that the vessel failure frequencies for the reactor

vessel beltline axial welds are lower than those for the case study. Based on this assessment, the

staff concludes that the applicant's TLAA on reactor vessel axial weld failure analyses satisfies

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Renewal Application Action Item 12 of the staff SER dated October 18, 2001, on BWRVIP-74.

The staff further concludes that the TLAA on reactor vessel axial weld failure analyses has been

projected to the end of the period of extended operation and is acceptable as evaluated in

accordance with the 10 CFR 54.21(c)(1)(ii) criterion.

Table 4.2.6-1 Comparison of NRC and the Applicant's 54 EFPY Mean RTNDT Calculations

for JAFNPP Reactor Vessel Beltline Axial Weld Probability of Failure Analyses

Limiting NRC 54 EFPY Applicant 54 EFPY

Pilgrim Mean RTNDT Calculations for Mean RTNOT Calculations for

"Mod 2" Case Study JAFNPP JAFNPP

(Note 1) (Note 1)

Alloy % Cu 0.219 0.219 0.219

Alloy % Ni 0.996 0.996 0.996

RTNDT(u) (oF) -2.0 -48 -48

Fluence 0.149 0.255 0.255

(1019 n/cm2 )

Chemistry Factor 232.0 231.1 231.1

ARTNDT ('F) 116.0 145.3 145.2

Mean RTNDT ("F) 114.0 97.3 97.2

NRC Vessel Failure 5.02 x 10-6 The Mean RTNDT is Lower The Mean RTNDT is Lower

Frequency (VFF) (Maximum VFF Value than the Mean RTDT in the than the Mean RTNDT in the

Criterion / Refer to: Note 2) Pilgrim Mod 2 Case Study: Pilgrim Mod 2 Case Study:

Conclusion Against the Acceptance criterion is met. Acceptance criterion is met.

Criterion (Note 2) (Note 2)

(Note 3)

Notes: (1) For the reactor vessel, the limiting axial weld material determined by the staff was

equivalent to that determined by the applicant. The limiting reactor vessel axial welds are

the Lower Shell Axial Welds 2-233 A, B, and C fabricated from Tandem Weld Heat

No. 27204/12008. The staff and the applicant both independently found an RTNoT(u) value

of -48.0 OF, a Copper content of 0.219 wt.-%, and a Nickel content of 0.996 wt.-% for this

tandem weld material.

(2) If the plant-specific mean RTNDT is less than the mean RTNDT of the limiting case study,

the staff concludes that probability of failure for the plant-specific axial weld under review

will be less than the NRC's maximum acceptable vessel failure frequency for the axial

weld assessed in the limiting reactor vessel axial weld case study. BWR plants that meet

this criterion may conclude that the probability of failure for their reactor vessel beltline

axial welds is acceptable and that the TLAA has been sufficiently projected through the

expiration of the period of extended operation and is acceptable when evaluated against

the 10 CFR 54.21 (c)(1)(ii)/2 TLAA acceptance criterion.

(3) In these calculations, calculation of the vessel failure frequency for the axial weld in the

case study analyses uses the case study's conditional probability of failure value

multiplied by a 1 x 10. frequency for initiation of a cold, overpressurization event. Thus,

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for the staff's calculation of the vessel failure frequencies for the Pilgrim "Mod 2" case

studies, the staff determined that the conditional probability for the axial welds was 5.02 x

10-3 for the Pilgrim "Mod 2" case study.

The limiting axial weld failure probability calculated by the staff in the BWRVIP-05 SER

Supplement assumes that "essentially 100 percent" (i.e., greater than 90 percent) examination

coverage of all reactor vessel axial welds can be achieved in accordance with ASME Code

Section XI requirements.

In RAI 4.2.6-1 dated January 12, 2007, the staff asked the applicant whether ISI examinations

achieved "essentially 100 percent" (i.e., greater than 90 percent) overall examination coverage of

the reactor vessel axial welds for the duration of the current operating license period. If not, the

staff requested references to the staff SER granting relief for limited-scope axial weld

examination coverage. If less than 90 percent overall exalmination coverage for the reactor vessel

axial welds, the staff asked the applicant to revise its TLAA of the reactor vessel axial welds to

account for the effects of the limited-scope examination coverage.

In its response dated February 12, 2007, the applicant stated that, due to various obstructions

within the reactor vessel, it had not been able to inspect "essentially 100%" of the reactor vessel

beltline axial welds. The applicant currently operates under ISI program relief that authorizes

limited-scope examination coverage for specified reactor vessel axial welds. The limited-scope

examinations overall covered 88 percent of the axial welds in the beltline region. The staff SER

dated July 21, 2004 documents the technical basis for granting this relief from the ASME Code

Section XI requirements mandating 100 percent examination coverage of all axial welds.

The applicant stated that the effect of this reduced examination coverage on the axial weld failure

probability would be small. The applicant pointed to the large margin between the 84.70 F mean

ART and the 128.5 0 F mean ART for the CEOG plant in the SER on BWRVIP-05 to determine

weld failure probability. The applicant determined that the difference between the 88 percent axial

weld examination coverage and the 90 percent minimum coverage required to meet the

"essentially 100%" examination coverage requirement was unlikely to offset this large margin.

The current relief for the limited-scope axial weld examination coverage is effective only through

the end of the current ISI interval and does not authorize reduced examination coverage of

reactor vessel axial welds beyond the end of the current ISI interval. The changes in metallurgical

conditions anticipated require an additional analysis for 54 EFPY and NRC approval to extend the

reactor vessel axial weld inspection relief through the end of the period of extended operation

interval by interval. The applicant must submit, interval by interval, either a request for an

alternative to ASME Code Section XI requirements pursuant to 10 CFR 50.55a(a)(3) or a request

for relief from ASME Code Section XI requirements pursuant to 10 CFR 50.55a(g)(6)(i) to

address future axial weld examinations if it achieves less than "essentially 100%" coverage.

The staff's review of mean RTNDT values was based on the applicant's fluence values in LRA

Section 4.2.1. As described in SER Section 4.2.1.2, the staff reviewed and accepted the

applicant's new methodology (submitted as Amendment 14 by letter dated November 5, 2007)

that was used for calculating the neutron fluence values. The staff found that the newly calculated

neutron fluence values remain bounded by the values that were submitted in the applicant's

original LRA. Therefore, the mean RTNDT value of the limiting reactor vessel axial weld remains

valid. Based on this, the staff concludes that the previously identified sOl 4.2.6-1 as described in

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the SER With Open Items issued on July 31, 2007, is now closed.

4.2.6.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

reactor vessel axial weld failure probability in LRA Section A.2.2.1.6:

The BWRVIP recommendations for inspection of reactor vessel shell welds are

based on generic analyses supporting an NRC SER. The generic-plant axial weld

failure rate is no more than 5 x 10-6 per reactor year as calculated in the

BWRVIP-74 SER. BWRVIP-05 showed that this axial weld failure rate is orders of

magnitude greater than the 40 year end-of-life circumferential weld failure

probability, and used this analysis -to justify relief from inspection of the

circumferential welds as described above.

The BWRVIP-74 SER states it is acceptable to show that the mean RTNDT of the

limiting beltline axial weld at the end of the period of extended operation is less

than the limiting value given in the SERs for BWRVIP-74 and BWRVIP-05. The

projected 54 EFPY mean RTNDT values for JAFNPP are less than the limiting 64

EFPY RTNDT in the analysis performed by the NRC staff (Table 2.6-5 of the

BWRVIP-05 SER). As such, this TLAA has been projected to the end of the period

of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

The applicant's UFSAR suipplement summary description for the TLAA of the reactor vessel axial

weld failure probability appropriately describes how the conditional failure probabilities for the

reactor vessel axial welds are bounded by the analysis in the staff's supplemental SER dated

March 7, 2000. However, the staff determines that the applicant must include in the UFSAR

supplement summary description for this TLAA an additional statement that addresses the limited

scope axial weld inspection coverage described in SER Section 4.2.6.2. The statement must

indicate specifically that, due to various obstructions within the reactor vessel, the applicant was

granted relief from the requirement of "essentially 100 percent" (greater than 90 percent)

examination coverage of all reactor vessel axial welds. The staff accepted the applicant's

determination that the limited-scope (less than 90 percent) examination coverage of the reactor

vessel axial welds would not offset the large margin between the limiting axial weld mean RTNDT

value of 84.7 0 F at 54 EFPY and the mean RTNDT value of 128.5 0F mean ART for the CEOG plant

in the staff SER for BWRVIP-05. Therefore, the axial weld failure probability would not exceed 5 x

106 per reactor operating year during the period of extended operation. The addition of this

statement to the applicant's UFSAR supplement summary description will be consistent with the

staff analysis for the TLAA of the reactor vessel axial weld failure probability in SER

Section 4.2.6.2.

In its response dated June 20, 2007, the applicant supplemented its response to RAI 4.2.6.1, and

added the following paragraph to UFSAR Section A.2.2.1.6:

Due to various obstructions within the reactor vessel, Entergy was granted relief by

the NRC from the requirements foe "essentially 100" (<90 percent) examination

coverage of all reactor vessel axial welds. The staff accepted JAFNPP's

determination that the limited-scope (,90 percent) examination coverage of the

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reactor vessel axial welds would not offset the large margin between the limiting

axial weld mean RTNDT value of 84.70 F for JAFNPP at 54 EFPY and the mean

RTNDT value of 128.50 F mean adjusted reference temperature for the CEOG

plant used in the NRC SER for BWRVIP-05. Therefore, the axial weld failure

probability would not exceed 5x1 0-6 per reactor operating year during the period of

extended operation.

On the basis of its review of the UFSAR supplement, the staff concludes that the summary

description of the applicant's actions to address reactor vessel axial weld failure probability is

adequate.

4.2.6.4 Conclusion

The staff reviewed the applicant's TLAA of the reactor vessel axial weld failure probability, as

summarized in LRA Section 4.2.6, including its RAI responses dated February 12, 2007, as

supplemented by letter dated June 20, 2007, and determines that the applicant appropriately

described how the conditional failure probability for the reactor vessel axial welds are bounded by

the analysis in the staff supplemental SER dated March 7, 2000, on the BWRVIP-05 Report for

the period of extended operation. Based on this, the staff concludes that the previously identified

sOl 4.2.6-1 as described in the SER With Open Items issued on July 31, 2007, is now closed.

The staff therefore concludes that the applicant's TLAA Section 4.2.6 and UFSAR Supplement

summary description A.2.2.1.6 are acceptable. The staff concludes that the applicant's TLAA

Section 4.2.6 and UFSAR Supplement A.2.2.1.6 for the reactor vessel axial weld failure

probability will comply with the 10 CFR 54.21(c)(1)(ii) acceptance criterion for TLAAs.

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that, for reactor vessel axial weld failure

probability, the analyses 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).

4.3 Metal Fatigue

Fatigue analyses are potential TLAA for Class I and selected non-Class 1 mechanical

components. Fatigue is an age-related degradation mechanism caused by cyclic stressing of a

component by either mechanical or thermal stresses that becomes evident by cracking of the

component. Components designed in accordance with ASME Code Section III, Subsection NB,

are required to have fatigue analyses. ASME Code Section III requires evaluation of fatigue by

considering design thermal and loading cycles. JAFNPP monitors transient cycles that contribute

to fatigue usage in accordance with requirements in TS 5.5.5. Cumulative usage factors (CUFs)

have been documented and the actual numbers of design transient cycles have been projected to

60 years. A program is in place to track cycles and to provide corrective actions if limits are

approached. The maximum CUFs identified for JAFNPP components are summarized in LRA

Table 4.3-1. Reactor coolant system (RCS) pressure boundary piping was designed to American

National Standards Institute (ANSI) B31.1 and secondary stresses (e.g., stress due to thermal

expansion and anchor movements) are analyzed for fatigue using stress intensification factors

(SIFs) and stress range allowables. The stress range allowables are a function of thermal design

cycles. In addition to metal fatigue analyses, fracture mechanics analyses of flaw indications

4-30
discovered during ISI are TLAA for those analyses based on time-limited assumptions defined by

the current operating term. When a flaw is detected during ISIs, the component that contains the

flaw can be evaluated for continued service in accordance with ASME Code Section XI. These

evaluations may show the component is acceptable at the end of the current operating term

based on projected inservice flaw growth. Flaw growth is typically predicted based on the design

thermal and loading cycles.

A metal component subject to cyclical loading at loads less than the static design load may fail

due to fatigue. Evaluations of metal fatigue of components may assume a number of thermal

transients or cycles for the current operating term. The validity of such metal fatigue evaluations

is reviewed for the period of extended operation. The GALL Report treats fatigue aging-related

degradations that require evaluation as TLAAs pursuant to 10 CFR 54.21(c). The applicant's

TLAA on metal fatigue is in LRA Section 4.3.

4.3.1 Class 1 Fatigue

JAFNPP Class 1 components evaluated for fatigue and flaw growth include the RPV and

appurtenances, certain reactor vessel internals, and the RCS pressure boundary. The JAFNPP

Class 1 systems include components within the ASME Code Section XI, Subsection IWB

inspection boundary. Fatigue evaluations were performed in the design of the JAFNPP Class 1

components in accordance with the requirements specified in ASME Code Section III. The fatigue

evaluations are contained in analyses and stress reports, and because they are based on a

number of transient cycles assumed for a 60-year plant life, these evaluations are considered

TLAA. Design cyclic loadings and thermal conditions for the Class 1 components are defined by

the applicable design specifications for each component. The original design specifications

provided the initial set of transients that were used in the design of the components and are

included as part of each component analysis or stress report.

LRA Section 4.3.1, the applicant's TLAA assessment for metal fatigue of Class 1 RCPB

components, states that metal fatigue analyses for RCPB components fit the 10 CFR 54.3 TLAA

definition. The applicant provides the design-basis operational and transient categories that form

the bases for the applicant's 40-year CUF value calculations in LRA Table 4.3-2, which includes

the design-basis values for these transient categories and the applicant's projections of the

number of cycles for these transients.

4.3.1.1 Reactor Vessel

4.3.1.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1.1 summarizes the evaluation of the reactor vessel fatigue for the period of

extended operation. The RPV was designed in accordance with ASME Code Section III. The

required fatigue analyses were based on an allowed number of transient cycles. An evaluation of

fatigue usage factors in 2002 accounting for 60 years of operation projected that all vessel

components would have fatigue usage factors below 1.0. Not all reactor vessel components have

fatigue usage factors. Therefore, the RPV fatigue TLAA remains valid for the period of extended

operation.

The applicant explained that the RPV, RPV supports, and RPV nozzle appurtenances were

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designed to the 1965 Edition of ASME Code Section III and that the original 40-year metal fatigue

evaluations for these components were based on the methods for calculating CUFs in ASME

Code Section III, Article NB-3000. The applicant added that the following RPV supports and RPV

nozzle appurtenances were analyzed to these CUF requirements:

" RPV closure shell

" RPV shell - closure region

" RPV closure region bolts

" RPV shell other than the closure and bottom head region

* RPV bottom head dome including penetrations

" RPV support skirt

" RPV feedwater nozzle safe end

" RPV feedwater nozzle inner blend radius

" core spray nozzle

" control rod drive (CRD) hydraulic system return nozzle (cut and capped)

" recirculation inlet nozzle safe end

* recirculation inlet nozzle thermal sleeve

" recirculation outlet nozzle

" RPV vent nozzle

" RPV 6-inch instrument/head nozzle

* CRD penetration nozzle

" RPV shroud support and attachments

" RPV basin seal skirt

The CUF values for the RPV, RPV supports, and RPV nozzle components are in LRA

Table 4.3-1. The applicant stated that the three most limiting commodity groups for metal fatigue

of the RPV, RPV supports, and RPV nozzle appurtenance components are the "core shroud

support and attachments," "the vessel shell - other than the closure flange and bottom head

regions," and the "feedwater nozzle safe end." The applicant specified CUF values of 0.90, 0.89,

and 0.84 for these component locations, respectively.

The applicant stated that the CUF values for the RPV, RPV supports, and RPV nozzles in LRA

Table 4.3-1 are bounding for the period of extended operation and that the TLAA on Class 1

metal fatigue is acceptable in accordance with 10 CFR 54.21(c)(1)(1). The applicant states that

the Fatigue Monitoring Program will maintain CUF values for the RPV, RPV supports, and RPV

nozzles for the period of extended operation.

4.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.1, to verify pursuant to 10 CFR 54.21(c)(11)(i), that the

analyses remain valid for the period of extended operation.

The scope of the CUF values in LRA Table 4.3-1 includes those for the RPV, RPV supports and

RPV nozzle components listed in SER Section 4.3.1.1.1. For these components, the applicant

concluded that the TLAA remains bounding for the period of extended operation and is

acceptable in accordance with 10 CFR 54.21(c)(1)(i). The staff reviewed the TLAA bases

documents for the validity of applicant's conclusion that the CUF values for the RPV, RPV

supports and RPV nozzle components would remain bounding for the period of extended

operation.

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The LRA indicates that the three most limiting RPV components (including nozzles and supports)

for fatigue are the RPV support skirt, RPV closure bolts (studs), and RPV feedwater (FW) nozzle

safe end. The applicant reported 60-year CUF values of 0.90 for the RPV support skirt, 0.89 for

the RPV shell (other than. the closure flange and bottom head regions), and 0.834 for the RPV

FW nozzle safe end.

The updated CUF calculations for the RPV components were based on the number of cycles for

the design-basis transients in calculation No. SIR-02-045, Revision 1. The updated CUF values in

SIR-02-045, Revision 1, for the RPV components were projected to be less than 1.0 with the

exception of the following components: (1) RPV closure bolts (studs), (2) RPV FW nozzle thermal

sleeve, and (3) RPV FW nozzle inner blend radius. The applicant reanalyzed the CUF values for

these three component locations in Minor Calculation Change No. DRN-03-00794.

The staff reviewed Minor Calculation Change No. DRN-03-00794 for whether the revised CUF

calculations for the RPV closure studs, RPV FW nozzle thermal sleeve, and RPV FW nozzle

inner blend radius were in accordance with design-basis requirements and whether the CUF

value revisions for these components were acceptable. Based on its review of these calculations,

the staff determined that the CUF values for these components reported in LRA Table 4.3-1 were

in accordance with ASME Code Section III and the requirements of updated design-basis

transient cycles.

The staff asked the applicant to clarify whether the RPV FW nozzle is subject to the leakage

bypass transients described in NUREG-0619 and, if so, whether the CUF calculation in Minor

Calculation Change No. DRN-03-00794 for this component accounts for this type of operational

transient.

In its response, the applicant stated that the FW nozzle area is subject to the bypass leakage

transients described in NUREG-0619 and that the updated CUF values for the RPV FW nozzle

inner blend radius include a rapid-cycle fatigue calculation to account for rapid leakage cycling

past the thermal sleeve of the nozzle. The staff confirmed that the CUF calculations for the FW

nozzle include a rapid-cycle fatigue calculation for the FW nozzle inner blend radius and that the

proper value for the FW nozzle is reflected in LRA Table 4.3-1. The staff also confirmed that the

updated CUF values for the remaining RPV components, RPV nozzles, and RPV support

components in these calculations are reflected appropriately in LRA Table 4.3-1.

Based on its review of the information in LRA Tables 4.3-1 and 4.3-2 and of the calculations in

SIR-02-045, Revision 1, and Minor Calculation Change No. DRN-03-00794, the staff concluded

that the updated CUF calculations in LRA Table 4.3-1 are valid for the period of extended

operation if the applicant demonstrates that the 60-year cycle projections for the plant's transients

would be bounded by the updated design-basis cycle numbers for the transients.

In RAI 4.3.1-1 dated February 23, 2007, the staff asked the applicant to clarify (1) the projected

60-year cycle numbers for the design-basis transients, (2) how the 60-year projections for these

transients were calculated as based on past cycle counting, and (3) why the 60-year cycle

projections for the design-basis transients in LRA Table 4.3-2 are valid.

In its letter dated June 20, 2007 (ML071770168), the applicant amended the LRA and provided

its response to RAI 4.3.1-1 on cycle projections. Specifically, the applicant amended the LRA to

update the 60-year cycle projections for the design basis transients based on plant operational

4-33
data since initial startup of the facility. The applicant also provided Report No. SIR-07-084,

Revision 1, "SI Response to NRC Requests for Additional Information for FitzPatrick

[June 8, 2007]," in its letter of June 20, 2007.

The staff reviewed Report No. SIR-07-084, Revision 1, and determined that the applicant has

reanalyzed and categorized those undefined operational transients that had been analyzed in

earlier design basis CUF calculations. The applicant also updated the 60-year cycle projections

for the following design basis transients:

* Category No. 3, "Startups," from 216 to 242

" Category No. 11, "Loss of FW Pumps, SIVs Close," from 10 to 11

• Category No. 15, "All Other SCRAMs," from 62 to 57

* Category Nos. 19-23, "Shutdowns," from 244 to 270

The startup and shutdown categories are the transients categories contribute the most to the

CUF calculations. The staff determined that the changes in the 60-year projections for these

categories amounts to a 10-12.5 percent increase in 60-year cycle projections for these

categories. The staff determined that the information provided in its response to RAI 4.3.1-1 and

Amendment 12 dated June 20, 2007, provides acceptable 60-year cycle projections for these

design transient categories.

The applicant amended its basis for accepting the TLAA from acceptance in accordance with

10 CFR 54.21(c)(1)(i) (i.e., the analysis remains valid for the period of extended operation) to

acceptance in accordance with 10 CFR 54.21(c)(1)(iii) (i.e., the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation). The staff concludes

that this is acceptable because the applicant will use its Fatigue Monitoring Program to assure

that the number of cycles recorded for the operational transients to date will remain below their

design-basis allowables and to ensure that the effects of thermal fatigue on the intended function

for these components will be managed for the period of extended operation, as accepted in

accordance with the requirements of 10 CFR 54.21(c)(1)(iii). This is in conformance with the

staffs position in GALL aging management program (AMP) X.M1, "Metal Fatigue of Reactor

Coolant Pressure Boundary," for accepting metal fatigue evaluations in accordance with the

criteria of 10 CFR 54.21(c)(1)(iii).

The applicant's Fatigue Monitoring Program is described and discussed in LRA Section B.1.12.

The staff evaluated the ability of the Fatigue Monitoring Program to manage the effects of

thermal fatigue on the intended functions of the RPV components in SER Section 3.0.3.2.10.

Based on this assessment, the staff concludes that the applicant has provided a valid basis for

concluding that the TLAA on metal fatigue of the RPV components is acceptable. RAI 4.3.1-1 is

resolved.

4.3.1.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

reactor vessel fatigue in LRA Section A.2.2.2.1 and in its letter dated June 20, 2007

(Amendment 12). On the basis of its review of the UFSAR, the staff finds that the summary

description of the applicant's actions to address reactor vessel fatigue is adequate.

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4.3.1.1.4 Conclusion

On the basis of its review, as discussed above for reactor vessel fatigue, the staff concludes that

the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the effects of aging on

the intended functions 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).

4.3.1.2 Reactor Vessel Internals

4.3.1.2.1 Summary of Technical Information in the Application

LRA Section 4.3.1.2 summarizes the evaluation of reactor vessel internals fatigue for the period

of extended operation. Although not mandatory, the design of the reactor vessel internals is in

accordance with the intent of ASME Code Section III. A fatigue analysis of the internals

determined that maximum fatigue usage occurs in the jet pump-shroud-shroud support area at

the ID of the jet pump diffuser adapter at the thin end of the tapered transition section. The

maximum 0.65 CUF in this area for 40 years of operation is projected to 60 years of operation by

multiplying by 1.5 for a 0.98 CUF for the ID of the jet pump diffuser at transition. There was also a

fatigue evaluation on the tie rod assemblies installed as part of the core shroud repair. The

maximum CUF for the tie rod components is 0.0575 for the spring rod based on 120

startups/shutdowns. The current number of startups/shutdowns allowed for 60 years of operation

is 233. Therefore, a conservative projection of the fatigue usage of the tie rods for 60 years of

operation would be (233/120) x 0.0575, which equals a CUF of 11. The analyses for the jet pump

diffuser at transition and the shroud tie rod assembly have been projected through the period of

extended operation.

4.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.2, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The applicant stated that the jet pump diffuser adapters and core shroud tie rod assemblies were

the only RPV internal components that had undergone design-basis CUF analyses for the CLB.

The LRA indicates that the CUF value for the jet pump diffuser adapters will be 0.98 at 60 years

of licensed operation. The staff noted that the period of extended operation will add 20 years to

the facility's 40-year licensed life; thus, a safety factor of 1.5 (i.e., by a factor = [1 + (20 years

/40 years)] ) is the minimum that must be applied to the 40-year jet pump diffuser adapter CUF

value to account for the period of extended operation. The adequacy of this method of analysis

for projecting the CUF values to 60 years is acceptable only if the method for projecting the cycle

numbers for the design-basis transients to 60 years is acceptable and if the 60-year cycle

projections are demonstrably lower than those for the cycles for the design-basis transients. As

noted previously, the staff asked the applicant in RAI 4.3.1-1 to address this issue; thus, the

staff's determination of whether the CUF is valid for the period of extended operation in

accordance with 10 CFR 54.21(c)(1)(ii) remains open pending resolution of RAI 4.3.1-1.

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In its letter dated June 20, 2007 (ML071770168), the applicant amended the LRA and provided

its response to RAI 4.3.1-1 on cycle projections. Specifically, the applicant amended the LRA to

update the 60-year cycle projections for the design basis transients based on plant operational

data since initial startup of the facility. The applicant also provided Report No. SIR-07-084,

Revision 1, "SI Response to NRC Requests for Additional Information for FitzPatrick

[June 8, 2007]," in its letter of June 20, 2007.

The staff reviewed Report No. SIR-07-084, Revision 1, and has documented its evaluation of this

report in SER Section 4.3.1.1.2. The staff determined that the updated 60-year cycle projection

for the design basis transients are bounded by the number of cycles assumed for in the

applicant's 60-year CUF calculations for the jet pump diffuser assembly adapters and the core

shroud tie rod assemblies. Based on this assessment, the staff concludes that the applicant has

provided an acceptable basis for projecting the CUF values for these components to the end of

the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii). In addition, the

applicant will use its Fatigue Monitoring Program to assure that the number of cycles recorded for

the operational transients to date will remain below their design basis allowables and to ensure

that the effects of thermal fatigue on the intended function for these components will be managed

for the period of extended operation, as accepted in accordance with the requirements of

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

This is in conformance with the staffs position in GALL AMP X.M1, "Metal Fatigue of Reactor

Coolant Pressure Boundary," for accepting metal fatigue evaluations in accordance with the

criteria of 10 CFR 54.21(c)(1 )(iii). The applicant's Fatigue Monitoring Program is described and

discussed in LRA Section B.1.12. The staff evaluated the ability of the Fatigue Monitoring

Program to manage the effects of thermal fatigue on the intended functions of the RPV

components in SER Section 3.0.3.2.10. Based on this assessment, the staff concludes that the

applicant has provided a valid basis for concluding that the TLAA on metal fatigue of the RPV

components is acceptable. RAI 4.3.1-1 is resolved.

4.3.1.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

reactor vessel internals fatigue in LRA Section A.2.2.2.1 and in its letter dated June 20, 2007

(Amendment 12). On the basis of its review of the UFSAR supplement, the staff concludes that

the summary description of the applicant's actions to address reactor vessel internals fatigue is

adequate.

4.3.1.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated for reactor vessel internals fatigue, that pursuant to 10 CFR 54.21(c)(1)(ii), the

analyses have been projected to the end of the period of extended operation, or that pursuant to

10 CFR 54.21(c)(1)(iii), the effects of aging on the intended functions 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).

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4.3.1.3 Class 1 Piping and Components

4.3.1.3.1 Summary of Technical Information in the Application

LRA Section 4.3.1.3 summarizes the evaluation of Class 1 piping and components for the period

of extended operation. All RCS pressure boundary piping is designed and analyzed in

accordance with ANSI B31.1. The ANSI B31.1 code addresses fatigue by using stress range

reduction factors to reduce stress allowable. Components with less than 7000 equivalent

full-temperature cycles are limited to the calculated stress allowable without reduction per

ANSI B31.1.0. Components that exceed 7000 equivalent full-temperature cycles have allowable

stresses reduced through the application of stress range reduction factors. As the reactor coolant

pressure boundary will not exceed 7000 full temperature cycles in 60 yearslof operation, existing

,stress analyses remain valid for the period of extended operation.

4.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.3, to verify pursuant to 10 CFR 54.21(c)(1)(i), that the

analyses remain valid for the period of extended operation.

The applicant's Class 1 piping components were all designed to ANSI B31.1 design code. The

ANSI B31.1 requires that the maximum allowable stress range be reduced if the projected

number of full thermal transients on the components is greater than 7000 cycles. The applicant

indicated that the total number of full thermal cycle transients projected through 60 years of

operation is less than 7000 and that, based on this projection, the analyses for these components

remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

The staff reviewed the thermal transients defined and summarized in LRA Table 4.3-2 and

confirmed that the total number of full thermal transients projected to the end of the period of

extended operation (i.e., through 60 years of licensed power operations) will be fewer than 7000.

Based on this confirmation, the staff concludes that the applicant has provided an acceptable

basis for the conclusion that the maximum allowable stress range analysis for the ASME B31.1

Class 1 piping components remains valid for the period of extended operation in accordance with

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

4.3.1.3.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

Class 1 piping and components fatigue in LRA Section A.2.2.2.1. On the basis of its review of the

UFSAR supplement, the staff concludes that the summary description of the applicant's actions

to address Class 1 piping and components fatigue is adequate.

4.3.1.3.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that, for Class 1 piping and components

fatigue, the analyses 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).

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4.3.2 Non-Class I Fatigue

4.3.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2 summarizes the evaluation of non-Class 1 fatigue for the period of extended

operation. The design of ASME Code Section III Code Classes 2 and 3 piping systems

incorporates the code stress reduction factor for determining acceptability of piping design for

thermal stresses. In general, 7000 thermal cycles are assumed, allowing a stress reduction factor

of 1.0 in the stress analyses. The applicant's evaluation of the validity of this assumption for

60 years of plant operation indicates that the assumption is valid and bounding. Therefore, the

pipe stress calculations are valid for the period of extended operation. Non-Class 1 components,

other than piping system components, require fatigue analyses only if built in accordance with

ASME Section I1, NC-3200 or ASME Section VIII, Division 2. The applicant has no non-Class 1

components built to these codes and therefore no TLAA for other than piping system

components.

4.3.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2, to verify pursuant to 10 CFR 54.21(c)(1)(i), that the

analyses remain valid for the period of extended operation.

During the audit and review, the staff reviewed LRA Section 4.3.2 on the TLAA on metal fatigue

for non-Class 1 components and plant design-basis documents. The staff determined that the

current ISI program indicates that the ASME Code Classes 2 and 3 piping systems are designed

in accordance with the ANSI B31.1 1967 Edition. The staff noted that the plant design-basis

document indicated the total number of full thermal cycles projected for non-Class 1 components

through 60 years of licensed operations is less than 7000 cycles. Based on this number, the staff

concludes that the stress calculations for the non-Class 1 piping will remain valid for the period of

extended operation.

4.3.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

non-Class 1 fatigue in LRA Section A.2.2.2.2 explaining how the number of full thermal transients

is projected to remain below 7000 cycles at the expiration of the period of extended operation

and, therefore, providing an acceptable description of the TLAA on metal fatigue for non-Class 1

components in that it shows how the maximum allowable stress range analysis for the

components remains valid for the period of extended operation in accordance with

10 CFR 54.21(c)(1)(i). On the basis of its review of the UFSAR supplement, the staff concludes

that the summary description of the applicant's actions to address non-Class 1 fatigue is

adequate.

4.3.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1 )(i), that, for non-Class 1 fatigue, the analyses

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remain valid for the period of extended operation. In addition, the staff concludes that the UFSAR

supplement contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21(d).

4.3.3 Effects of Reactor Water Environment on Fatigue Life

In Generic Safety Issue (GSI)-190, "Fatigue Evaluation of Metal Components for 60-year Plant

Life," the staff assessed the generic effects of reactor coolant environment on fatigue life of

Class 1 components. In accordance with interim staff guidance document ISG-16, "Time-Limited

Aging Analyses (TLAAs) Supporting Information for License Renewal Applications," the staff

position is that the environmental effects of the reactor coolant environments must be evaluated

for their impacts on the 60-year metal fatigue CUF values for high-fatigue CUF locations listed in

vintage BWR plants.

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3 summarizes the evaluation of effects of reactor water environment on fatigue

life for the period of extended operation. NUREG/CR-6260 applied fatigue design curves for

environmental effects on several plants and NUREG/CR-6260 Section 5.7 identified the following

component locations as most sensitive to environmental effects for General Electric plants similar

to JAFNPP. These locations and the corresponding calculations are directly relevant:

• reactor vessel shell and lower head

* reactor vessel FW nozzles

• RR piping (including inlet and outlet nozzles)

• core spray line reactor vessel nozzle and associated piping

• residual heat removal (RHR) return piping

* FW piping

The applicant evaluated the limiting locations using the guidance of Volume 2, Section X.M1 of

NUREG-1 801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated

September 2005, and the fatigue life correction factors, Fen, reported in NUREG/CR-5704 and

NUREG/CR-6583. Four of nine components reviewed at these locations have

environmentally-adjusted CUFs greater than 1.0. Prior to the period of extended operation, for

each location with a CUF that may exceed 1.0 the applicant will implement one or more of the

following: (1) further refinement of the fatigue analyses to lower the predicted CUFs to less than

1.0 using an NRC-approved method; (2) management of fatigue at the affected locations by an

inspection program reviewed and approved by the staff (e.g., periodic non-destructive

examination of the affected locations at inspection intervals to be determined by an acceptable

method); or (3) repair or replacement of the affected locations. If the applicant opts to manage

environmentally-assisted fatigue during the period of extended operation, details of the aging

management program such as scope, qualification, method, and frequency will be submitted prior

to the period of extended operation. The effects of environmentally-assisted thermal fatigue for

the limiting locations identified in NUREG-6260 have been evaluated. Depending on the option

chosen, which may vary by component, this TLAA will be projected through the period of

extended operation or the effects of environmentally-assisted fatigue will be managed. For those

locations with CUFs less than 1.0, the TLAA has been projected through the period of extended

operation.

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4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.3, to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation and, pursuant to

10 CFR 54.21 (c)(1 )(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

In NUREG/CR-6260, the staff evaluated a sample of RCS components for the impacts of the

reactor coolant environment on their thermal fatigue analyses. The applicant selected the

following BWR RCS component locations listed in NUREG/CR-6260 to evaluate the impact of the

reactor coolant environment on their thermal fatigue analyses:

" RPV shell and lower head

* RPV FW nozzles

* RR piping (including inlet and outlet nozzles)

" core spray line nozzle to the RPV and associated piping

* RHR return line piping

" FW piping

The applicant stated that, of the locations listed for a similar vintage BWR in NUREG/CR-6260, it

had updated 60-year CUF calculations for the RPV shell, RPV bottom head, RPV FW nozzle safe

end, RPV recirculation inlet nozzle thermal sleeve, RPV recirculation outlet nozzle, and RPV core

spray nozzles.

The applicant made environmental adjustments of CUF values by multiplying the 60-year CUF

values for the specific component locations (as listed in LRA Table 4.3-1) by the appropriate

fatigue life correction factor (Fen) value derived from NUREG/CR-6583 if the specific component

was fabricated from carbon or low-alloy steel or from NUREG/CR-5704 if fabricated from

austenitic stainless steel. The applicant provided in its design-basis document bases for the

calculations of the Fen adjustment factors.

The staff determined that in 1988 the applicant had changed its basis for controlling the chemistry

of the reactor coolant from normal water chemistry (NWC) to hydrogen water chemistry (HWC)

procedural controls. The change from NWC to HWC procedural controls significantly changes the

concentration of dissolved oxygen in the reactor coolant. During the audit and review, the staff

reviewed the applicant's design-basis document and determined that the environmental

adjustments of the CUF values were based on oxygen concentration values for HWC

implementation at the facility. This determination assumes that the facility had been operating

under HWC conditions since initial commercial operation of the plant on July 28, 1975.

During the audit and review, the staff asked the applicant to clarify whether it had factored the

actual NWC oxygen concentrations into the Fen calculations for the period from initial plant

operation to 1988, when the plant started to implement NWC procedures.

In its letter dated February 1, 2001 (ML0704401270), the applicant indicated that it will recalculate

the Fen values to account for the oxygen concentrations when the plant implemented NWC and

HWC procedures and apply the revised Fen values to the CUF values in LRA Table 4.3-3. The

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applicant included this process as part of Commitment No. 20, which was included in LRA

Amendment 5 dated February 1, 2007, and resubmitted in LRA Amendment 9, dated

April 6, 2007 (ML0710603900).

The staff noted that the revised environmentally-adjusted CUF values for the RPV shell, RPV FW

nozzle safe end, RPV recirculation inlet nozzle thermal sleeve, and RPV recirculation outlet

nozzle were projected to be above 1.0 for the period of extended operation. To address this

issue, in its letters dated February 1, and April 6, 2007, the applicant amended the LRA to include

Commitment No. 20 as follows:

At least 2 years prior to entering the period of extended operation, for the locations

identified in NUREG/CR-6260 for BWRs of the JAFNPP vintage, JAFNPP will

implement one or more of the following:

(1) Refine the fatigue analyses or develop new analyses (Class 1 RHR piping and

Class1 feedwater piping locations), if necessary, to determine valid CUFs less than

1 when accounting for the effects of reactor water environment. This includes

applying the appropriate Fen factors to valid CUFs determined in accordance with

one of the following:

1. For locations with existing fatigue analysis valid for the period of

extended operation, use the existing CUF to determine the environmentally

adjusted CUF.

2. More limiting JAFNPP-specific locations with a valid CUF may be added

to the NUREG/CR-6260 locations.

3. Representative CUF values from other plants, adjusted to or enveloping

the JAFNPP plant specific external loads may be used if demonstrated

applicable to JAFNPP.

4. For locations, including NUREG/CR-6260 locations, an analysis using

the NRC-approved version of the ASME code in the 2001 Edition up to an

inclusive of the 2003 Addenda may be performed to determine a valid CUF.

The determination of Fen will account for operating time with normal water

chemistry and operating time with hydrogen water chemistry.

(2) Manage the effects of aging due to fatigue at affected locations by an

inspection program that has been reviewed and approved by the NRC (e.g.,

periodic nondestructive examination of the affected locations at inspection intervals

to be determined by a method acceptable to the NRC).

(3) Repair or replace the affected locations prior to the period of extended

operation and the location exceeding a CUF of 1.0.

Should JAFNPP select the option to manage the aging effects due to

environmental-assisted fatigue during the period of extended operation, details of

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the aging management program such as scope, qualification, method, and

frequency will be submitted to the NRC at least 2 years prior to the period of

extended operation.

The staff noted that under Commitment No. 20 the applicant must either (1) redo the 60-year

environmentally-adjusted CUF calculations for the Class 1 locations in LRA Table 4.3-3, including

new environmental CUF calculations for the Class 1 portions of the RHR and FW piping, (2)

manage the aging effects due to fatigue by using an NRC-approved AMP to inspect these

component locations prior to the period of extended operation, or (3) repair or replace the

affected components before exceeding a environmentally-adjusted CUF value of 1.0. If using the

first option as the basis for acceptance of the TLAA on environmental fatigue, the applicant will

submit the results of the environmentally-adjusted CUF calculations for review and approval at

least two years prior to the period of extended operation.

In LRA Amendment No. 12, June 20, 2007 (ML071770168), the applicant amended the LRA to

characterize this TLAA as an aging management program in accordance with the criteria of

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

By letter dated July 25, 2007 (ML072010267), the staff sought further clarifications on the options

that could be used under LRA Commitment No. 20 and issued RAI 4.3.3-1 to address this issue.

In RAI 4.3.3-1, the staff asked the applicant to identify which option or options under LRA

Commitment No. 20 would be used to satisfy the commitment when implemented and, for each

option selected to meet the commitment, to provide a sufficient detailed description of the

methodology that would be used to satisfy the option. The staff informed the applicant that the

information requested in the RAI was necessary in order for the staff to make a determination on

the acceptability of the applicant's TLAA on environmentally-assisted fatigue. The staff therefore

requested that the information in the response to RAI 4.3.3-1 be submitted as an amendment of

the LRA. The specific details of RAI 4.3.3-1 were enclosed with the letter (ADAMS Accession

No. ML072010267).

The staffs determination on the acceptability of the TLAA on environmentally-assisted fatigue is

pending submittal of the applicant's response to RAI 4.3.3-1 and the staffs review of the

response to this RAI. This was identified as 01 4.3.3-1 in the staff SER With Open Items issued

on July 31, 2007.

The applicant responded to RAI 4.3.3-1 (01 4.3.3-1) by letter dated August 14, 2007, and

supplemented its response in a letter dated November 5, 2007. In these letters, the applicant

amended the LRA and supplemented Commitment No. 20 to justify its environmentally-assisted

fatigue analysis. In the letter dated November 5, 2007, the applicant clarified that Option 1 of

Commitment No. 20 for refined CUF calculations is consistent with NRC recommendations for

periodic CUF updates in "monitoring and trending" (i.e., program element 4) of GALL AMP X.M1,

"Metal Fatigue of the Reactor Coolant Pressure Boundary," and for "corrective actions" in GALL

AMP X.M1. The applicant also clarified that Options 2 and 3 of Commitment No. 20 are corrective

actions consistent with those recommended in "corrective action" (i.e., program element 7) of the

same GALL AMP. With these clarifications, the applicant amended the LRA to bring Commitment

No. 20 within the scope of the applicant's Fatigue Monitoring Program and to credit this AMP as

the basis for acceptance of this TLAA in accordance with 10 CFR 54.21(c)(1)(iii). These changes

are consistent with NRC recommendations in GALL AMP X.M1, "Metal Fatigue of the Reactor

Coolant Pressure Boundary," and acceptable. The following paragraphs report the staff's

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evaluation of additional information.

The "corrective actions" of GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure

Boundary," state that acceptable corrective actions include repair, replacement, or a rigorous

analysis of the component to demonstrate that the design limit will not be exceeded during the

period of extended operation. The staff reviewed the three options in Commitment No. 20

included in the LRA as corrective actions to address those limiting RCPB components with

projected environmentally-assisted CUFs in excess of the environmentally-assisted fatigue

analysis limit (i.e., 1.0).

The staff reviewed the applicant's implementation plan for Option (1) (i.e., implementation of

refined environmentally-assisted CUF calculations) of Commitment No. 20 stated in the

applicant's letter dated August 14, 2007, against the staff. recommendation in SRP-LR

Section 4.3.3.2, "Generic Safety Issues." The staff determined that the RAI response indicated

that the refined environmentally-assisted fatigue calculations would be based on

recommendations of NUREG/CR-6583 for steel and NUREG/CR-5704 for stainless steel

components and that the methods for determination of stresses and fatigue usage factors would

be in accordance with an NRC-endorsed edition of ASME Code Section III, Division 1,

Subsection NB, Subarticles NB-3200 or NB-3600, as applicable to the specific component.

Based on this response, the staff determined that the implementation plan for Option (1) of

Commitment No. 20 indicates that the applicant will use NRC-approved methods for reanalysis

and that the option conforms with the "corrective actions" recommendations in the both the

SRP-LR and GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant Pressure Boundary."

Based on this determination, that staff concludes that Option (1) of Commitment No. 20 is an

acceptable "corrective action" for this TLAA.

The applicant's response dated August 14, 2007 to RAI 4.3.3-1 stated that, if Option (2) of

Commitment No. 20 is selected for corrective action, the inspection program for implementing the

option would meet the following criteria: (1) the inspection program would be based on the ten

AMP elements as defined in Branch Technical Position RLSB-1, (2) the applicant would submit

the AMP for NRC review and approval at least two years before the period of extended operation,

and (3) the method of inspection would be based on a qualified volumetric examination

technique. ASME Code Section XI, Paragraph IWB-3740(a) states that, "Appendix L provides

procedures that may be used to assess the effects of thermal and mechanical fatigue concerns

on component acceptability for continued service." ASME Code Section XI,

Paragraph IWB-3740(b) states that, "Appendix L provides procedures that may also be used

when the calculated fatigue usage exceeds the fatigue usage limit defined in the original

Construction Code." ASME Code Section XI, Appendix L, Paragraph L-3400 states that surface

or volumetric examinations of RCPB components may verify component acceptability for further

service.

Based on this response, the staff determined that the implementation plan for Option (2) of

Commitment No. 20 conforms to the examination provisions of ASME Code Section XI,

Appendix L, Paragraph L-3400, and with "corrective actions" recommended in GALL AMP X.M1,

"Metal Fatigue of the Reactor Coolant Pressure Boundary." Based on this determination, the staff

concludes that Option (2) of Commitment No. 20 is an acceptable "corrective action" option for

this TLAA.

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The applicant's response dated August 14, 2007, to RAI 4.3.3-1 also stated, that if Option (3)

(repair or replacement of the affected locations) is selected for corrective action, repair or

replacement would be in compliance with ASME Code Section XI. The staff determined that

implementation of Option (3) based on ASME Code Section XI requirements is consistent the

"corrective actions recommended in GALL AMP X.M1, "Metal Fatigue of the Reactor Coolant

Pressure Boundary." On this basis, the staff concludes that Option (3) of Commitment No. 20 is

also an acceptable "corrective action" option for this TLAA.

Based on these determinations, the staff concludes that the corrective actions in the applicant's

response to RAI 4.3.3-1 are acceptable because implementation of Commitment No. 20 will be in

accordance with NRC-approved methods. Therefore, the staff concludes that the TLAAon

environmentally-assisted fatigue is in accordance with 10 CFR 54.21(c)(1)(iii) and acceptable.

The applicant has credited the Fatigue Monitoring Program, amended to include the Commitment

No. 20 corrective action options, to manage the effects of aging during the period of extended

operation. Therefore, the staff's concern described in RAI 4.3.3-1 is resolved and 01 4.3.3-1 is

closed.

4.3.3.3 UFSAR Supplement

The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of

effects of reactor water environment on fatigue life in LRA Section A.2.2.2.3. The staff has

determined that the UFSAR Supplement summary description in LRA Section A.2.2.2.3

adequately summarizes the options relied on for TLAA acceptance and that Commitment No. 20

appropriately applies to the assessment in LRA Section 4.3.3 and to the UFSAR Supplement

summary description in LRA Section A.2.2.2.3 and LRA Amendment No. 12. On the basis of its

review of the UFSAR supplement, the staff concludes that the summary description of the

applicant's actions to address effects of reactor water environment on fatigue life is adequate.

4.3.3.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

committed to further activities to ensure that, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects

of aging on the intended function(s) will be adequately managed for the period of extended

operation. Based on this, the staff concludes that the previously identified sOl 4.2.3-1, is resolved

and is now closed. 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).

4.4 Environmental Qualification of Electric Equipment

The 10 CFR 50.49 environmental qualification (EQ) program is a TLAA for purposes of license

renewal. The TLAA of the EQ electrical components includes all long-lived, passive, and active

electrical and 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 loss of

coolant accidents or high-energy line breaks. EQ equipment comprises safety-related and Q-list

equipment, nonsafety-related equipment the failure of which could prevent satisfactory

accomplishment of any safety-related function, and necessary post-accident monitoring

equipment.

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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.

4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 summarizes the evaluation of EQ of electric equipment for the period of

extended operation. The Environmental Qualification of Electric Components Program manages

component thermal, radiation, and cyclical aging, as applicable, through the use of aging

evaluations based on 10 CFR50.49(f) qualification methods. As required by 10CFR 50.49, EQ

components not qualified for the current license term will be refurbished or replaced or their

qualification will be extended before they reach the aging limits established in the evaluation.

Aging evaluations for EQ components that specify a qualification of at least 40 years are

considered TLAAs for license renewal. The existing EQ program that maintains these EQ

components in accordance with their qualification bases was established to meet commitments

for 10 CFR 50.49. Consistent with GALL Report Section X.E1, "Environmental Qualification (EQ)

of Electric Components," the program includes consideration of operating experience to modify

qualification bases and conclusions, including qualified life. Compliance with 10 CFR 50.49

provides reasonable assurance that components can perform their intended function(s) during

accident conditions with the effects of inservice aging. Consistent with NRC guidance in RIS

2003-09, no additional information is required to address GSI 168, "EQ of Electrical

Components." Review of the existing program and operating experience shows that continued

implementation of the Environmental Qualification of Electrical Components Program provides

reasonable assurance that the aging effects will be managed and that the in-scope EQ

components will continue to perform their intended function(s) for the period of extended

operation.

4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4, to verify pursuant to 10 CFR 54.21(c)(1)(iii), that the effects

of aging on the intended function(s) will be adequately managed for the period of extended

operation.

The staff reviewed LRA Section 4.4 and the plant-basis document to determine whether the

applicant's information was adequate under 10 CFR 54.21(c)(1). For the electrical equipment in

the basis document, the applicant uses the 10 CFR 54.21 (c)(1 )(iii) TLAA evaluation to

demonstrate that the aging effects of EQ equipment will be adequately managed during the

period of extended operation. The staff reviewed the EQ Program to determine whether the

electrical and instrumentation and control (I&C) components covered under this program will

continue to perform intended functions consistent with the CLB for the period of extended

operation. The staff's evaluation of component qualification focused on how the EQ Program

manages the aging effects to meet the 10 CFR 50.49 requirements.

The staff audited the information in LRA Section B.1.10 and program-bases documents available

at the applicant's engineering office. On the basis of its audit, the staff finds that the EQ Program,

for which the applicant claimed consistency with GALL AMP X.E1, "Environment Qualification of

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Electrical Components," is consistent. Therefore, the staff finds that the EQ Program can

programmatically manage the qualified life of components within the scope of license renewal.

The EQ Program reasonably assures management of aging effects so components within its

scope will continue to perform intended functions for the period of extended operation.

4.4.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

environmental qualification of electric equipment in LRA Section A.2.2.3. On the basis of its

review of the UFSAR supplement, the staff concludes that the summary description of the

applicant's actions to address environmental qualification of electric equipment is adequate.

4.4.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that, for environmental qualification of electric

equipment, the effects of aging on the intended function(s) will be adequately managed for the

period of extended operation. The staff also concludes that the 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

4.5.1 Summary of Technical Information in the Application

LRA Section 4.5 states that evaluation of concrete containment tendon prestress is not applicable

because there are no pre-stressed tendons in the containment building.

4.5.2 Staff Evaluation

The containment has no prestressed tendons; therefore, the staff finds this TLAA not required.

4.5.3 UFSAR Supplement

The staff concludes that no UFSAR supplement is required because JAFNPP has no

pre-stressed tendons in the containment building.

4.5.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that this TLAA is not required.

4.6 Containment Liner Plate, Metal Containment, and Penetrations Fatigue

Analysis

JAFNPP is a BWR with a Mark I containment consisting of a freestanding steel drywell, vent

system, and steel pressure suppression chamber (torus). Large-scale testing of the Mark III

containment and in-plant testing of Mark I primary containment systems found additional

hydrodynamic loads not considered in the original containment design. The Mark I Owners group

initiated the Mark I Containment Program to develop a generic load definition and structural

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analysis techniques. The staff evaluation of the generic load definition and structural assessment

techniques is in NUREG-0661, " Safety Evaluation Report, Mark I Containment Long-Term

Program, Resolution of Generic Technical Activity A-7," dated July 1980. The Mark I Containment

Long-Term Program evaluation included fatigue analyses of the torus, the discharge piping

system, and attached piping.

4.6.1 Fatigue of Primary Containment

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 summarizes the evaluation of primary containment fatigue for the period of

extended operation. Analysis of the containment as part of the Mark I containment long-term

program was by methods and assumptions consistent with NUREG-0661. The Mark I

containment long-term program analyzed the torus and attached piping systems for fatigue due

to mechanical loadings as well as thermal and anchor motion. This analysis was based on

assumptions of the number of safety relief/valve actuations, operating basis earthquakes, and

accident conditions during the life of the plant. The analysis considered all BWR plants utilizing

the Mark I containment design and concluded that for all plants and piping systems considered,

the fatigue usage factor for an assumed 40-year plant life was less than 0.5. Extending plant life

by an additional 20 years would produce a usage factor below 0.75, less than 1.0, so the fatigue

criteria are satisfied. This TLAA has been projected through the period of extended operation.

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6.1, to verify pursuant to 10 CFR 54.21 (c)(1 )(ii), that the

analyses have been projected to the end of the period of extended operation.

The staff review of the Standard Review Plan (SRP) Section 4.6.1 evaluation of the containment

liner plates, metal containment, and penetrations sleeves found that the applicant's code of

record requires a fatigue analysis for the torus and attached piping systems from mechanical

loadings as well as thermal and anchor motion, and for this reason the staff reviewed the torus

and attached piping system fatigue evaluation for the period of extended operation as required by

10 CFR 54.21(c). During the audit and review, the staff asked the applicant for an estimate of the

total number of 60-year Safety Relief Valve (SRV) actuations in the design fatigue evaluation.

In its response, the applicant stated that all domestic Mark I BWRs appear to meet the GE Mark I

Containment Program (MPR-751) (Augmented Class 2/3 Fatigue Evaluation Method and Results

for Typical Torus Attached and SRV Piping Systems, November 1982) for both the current

operating license period and the period of extended operation. The applicant has tracked SRV

actuations from October 1974 to November 4, 2006, and recorded a total of 564 representing

approximately 32 years of operation. Conservatively assuming each of the 11 valves has lifted on

every actuation, the estimated number of lifts for each valve for 60 years is (60/32) x 564 = 1058

actuations in 60 years.

The plant-specific analysis (Teledyne Engineering Services (TES) document TR-5321-2) stated

that the SRV penetrations are qualified for 7500 cycles of maximum load. On this basis, the

projected CUF for 60 years is 0.141.

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The staff also asked the applicant for a fatigue evaluation of the SRV discharge and other

attached piping. The applicant's response referred to the plant-specific stress analysis

(TR-5321-2) for various load combinations; however, it does not include a fatigue evaluation of all

of the other torus attached piping (TAP). TAP is bounded by the GE Mark I Containment

Program, which considered fatigue usage factors less than 0.5 for an assumed 40-year plant life

for all piping systems. The staff noted that an additional 20 years of plant life would indicate

usage factors below 0.75, less than 1.0, satisfying the fatigue criterion. The staff concludes that

the applicant's evaluation adequately demonstrated that fatigue usage will not exceed its

allowable limit during the period of extended operation. Therefore, the staff finds that the

applicant has projected the TAP analysis for the period of extended operation in accordance with

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

The applicant also stated that the plant-specific analysis (TR-5321-2) addresses the SRV

discharge piping and its supports as well as the main vent penetration through which the SRV

discharge enters the torus. This analysis states that the SRV penetrations are qualified for 7500

cycles of maximum load with fewer than 50 cycles at maximum load and 4500 cycles at partial

load expected for the SRVs. The analysis concludes, "Since the 7500 cycles of maximum loads

bounds both of these by such a large margin and since no other significant loads are imposed on

the line, the penetration was determined to be acceptable for fatigue without further evaluation."

The 40-year cycles increased by 1.5 for the period of extend operation would be only 75

maximum-load and 6750 low-load cycles for a total of 6825 mixed-load cycles, fewer than the

7500 maximum load cycles permitted. The staff finds that the fatigue analysis for torus

penetrations thus remains valid for the period of extended operation in accordance with

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

The applicant also indicated that the plant-specific analysis (TR-5321-2) refers to the generic GE

Mark I Containment Program for other TAP. The results of that program (based on 40 years of

operation) were that 92 percent of the TAP would have CUFs less than 0.3 and 100 percent less

than 0.5. These CUFs conservatively multiplied by 1.5 show that for 60 years of operation, 92

percent of the TAP would have CUFs below 0.45 and 100 percent below 0.75. These calculations

thus have been projected through the period of extended operation in accordance with

10 CFR 54.21(c)(1)(ii). The staff reviewed the applicant's response and finds it acceptable

because it reasonably summarizes the information presented in LRA Section 4.6.1.

4.6.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

primary containment fatigue in LRA Section A.2.2.4. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant's actions to

address primary containment fatigue is adequate.

4.6.1.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that, for primary containment fatigue, the

analyses 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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4.7 Other Plant-Specific TLAAs

LRA Section 4.7 summarizes the evaluation of the following plant-specific TLAAs:

" recirculation isolation valves

" leak-before-break

" TLAA in BWRVIP documents

4.7.1 Recirculation Isolation Valves

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 summarizes the evaluation of recirculation isolation valves for the period of

extended operation. In reference to the recirculation isolation valves, the UFSAR states, "For

fatigue evaluations consider 30 cycles of normal pressurization followed by blowdown and

270 cycles of normal pressurization followed by normal depressurization." LRA Section 4.7.1

states that "As these are not ASME-class valves, no specific fatigue analysis was required;

however, the number of cycles suggested by the UFSAR is greater than the number of cycles

allowed as part of the Fatigue Monitoring Program, so the transients suggested will not be

exceeded. Thus this TLAA will remain valid for the period of extended operation in accordance

with 10 CFR 54.21(c)(1)(i)."

4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the

analyses remain valid for the period of extended operation.

The applicant dispositioned this TLAA under 10 CFR 54.21(c)(1)(i) and provided a

UFSAR Supplement summary accordingly.

Under the 10 CFR 54.21(c)(1 )(i) disposition option, the applicant must demonstrate that "The

analyses remain valid for the period of extended operation."

The applicant in its TLAA quotes the UFSAR: "For fatigue evaluations consider 30 cycles of

normal pressurization followed by blowdown and 270 cycles of normal pressurization followed

by normal depressurization." The applicant further states that these are not ASME valves and that

no specific fatigue analysis was required. The staff notes that UFSAR Section 4.3.4 states that

"The Reactor Recirculation System is designed and constructed to meet the requirements

described in Section 16.2." Section 16.2.3.4, "Piping," states that:

The piping systems were designed in accordance with ANSI B31.1.0 and no formal

fatigue analysis was required. It was, therefore, not required to categorize the

design transients or combination of transients which were included in each loading

conditions and the number of design cycles for each transient or combination of

transients. No such categorization was made for the safety/relief valves, main

steam line isolation valves, recirculation system valves and pumps, or other

components in the Reactor Coolant Pressure Boundary because the applicable

codes did not require such categorization.

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The staff further notes that, in reference to the 28-inch suction and discharge recirculation valves,

UFSAR Table 16.2-7, under the first column titled "Criteria-Method" specifies the following:

ASME Boiler and Pressure Vessel Code, Nuclear Vessels Section III Article 4

In the second column, titled "Method of Analysis," UFSAR Table 16.2-7 specifies the following:

For fatigue evaluations consider 30 cycles of normal pressurization followed by

blowdown and 270 cycles of normal pressurization followed by normal

depressurization. Plot results.

In the third column, titled "Allowable Stress or Minimum Required Dimension," UFSAR

Table 16.2-7 specifies the following requirement:

Plotted results show that the flange region of the valve is adequate for the defined

service.

In RAI 4.7-1 dated January 12, 2007, the staff requested from the applicant information as

described in 10 CFR 54.21(c)(1)(i).

In its response dated February 12, as supplemented April 6, 2007, the applicant stated that it

could not identify a fatigue evaluation for these valves. It is the applicant's stated opinion that

contents of UFSAR Table 16.2-7, in reference to these valves, are merely for guidance as to what

cycles to include if the analysis is performed. The applicant further stated that it had evaluated

the number of cycles listed in UFSAR Table 16.2-7 conservatively as if they had been used in a

fatigue analysis and that if a fatigue analysis was done, it will remain valid for the period of

extended operation (thus fulfilling Criterion (i)) because the number of cycles specified in

Table 16.2-7 is greater than the number monitored and allowed by the Fatigue Monitoring

Program (FMP). In response to the staff's RAI, the applicant indicated that the FMP monitored

and allowed values are in LRA Table 4.3-2. This table is subject to RAI 4.3.1-1. On June 20, 2007

the applicant submitted Amendment 12 of its LRA (ADAMS accession number ML071770168)

which includes supplemental response to RAI 4.3.1-1. Attachment 1 Table C-2 of LRA

Amendment 12 contains the current design basis allowable cycles as listed in UFSAR Table 4.2-3

and updates the 60-year cycle projections of LRA Table 4.3-2. The following transient cycle

values are included in Table C-2.

Startups

Current Design Basis = 233

60-year projection = 242

Single Relief Valve Blowdown

Current Design Basis = 2

60-year projection = 1

Shutdowns

Current Design Basis = 233

60-year projection = 270

By comparison, the staff notes that these values are enveloped by the cycle values specified in

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UFSAR Table 16.2-7 (see above) for the Recirculation Isolation Valves. Therefore, the staff

concurs with the applicant that, if there is a fatigue analysis reflected by UFSAR Table 16.2-7, the

applicant has demonstrated in accordance with 10 CFR 54.21(c)(1)(i) that the analysis will remain

valid for the period of extended operation.

4.7.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

recirculation isolation valves in LRA Section A.2.2.5. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant's actions to

address recirculation isolation valves is adequate.

4.7.1.4 Conclusion

On the basis of its review for the recirculation isolation valves, as discussed above, the staff

concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21 (c)(1)(i), that, for

recirculation isolation valves, the analyses remain valid for the period of extended operation. The

staff also concludes that the UFSAR supplement contains an appropriate summary description of

the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.2 Fatigue Crack Growth Analysis for UFSAR Section 16.3.2.2

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2, as amended by letter dated April 6, 2007, summarizes the evaluation of a

fatigue crack growth analysis in UFSAR Section 16.3.2.2 for the period of extended operation.

Specifically, the section describes an evaluation of the necessity of pipe whip restraints the

installation of which could affect plant safety adverse by hindering ISIs. Part of the evaluation

calculates the growth of a crack prior to sudden rupture using a fatigue analysis to predict the

propagation of cracks that originate at defects permitted by the ANSI B31.7 Code. UFSAR

Section 16.3.2.2 concludes that for cyclic stress equal to the design yield strength with defect

sizes permitted by the code, the fatigue life of each pipe line is greater than 100,000 transient

cycles. While the applicant believes the 100,000 transient cycles is not a time-limited assumption

defined by the current operating term, it has chosen to evaluate the analysis conservatively as a

TLAA.

As shown in LRA Table 4.3-2, no transients are projected to exceed 100,000 cycles during

60 years of operation. Because transient cycles will not exceed 100,000 cycles in 60 years of

operation, the fatigue crack growth analysis in UFSAR 16.3.2.2 remains valid for the period of

extended operation in accordance with 10 CFR 54.21(c)(1)(i).

4.7.2.2 Staff Evaluation

The staff reviewed LRA Section 4.7.2, as amended by letter dated April 6, 2007, to verify that it is

in accordance with 10 CFR 54.21 (c)(1)(i), and that the analysis remains valid for the period of

extended operation.

The staff finds that the applicant appropriately evaluated the analysis in UFSAR Section 16.3.2.2

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as a TLAA.

LRA Table 4.3-2 shows the projected cycles for 60 years of operation. The staff finds that the

number of transient cycles will not exceed 100,000 for the period of extended operation.

4.7.2.3 Conclusion

The staff reviewed the applicant's TLAA for fatigue crack growth analysis in UFSAR

Section 16.3.2.2 as summarized in LRA Section 4.7.2 and amended by letter dated April 6, 2007.

The staff concludes that the applicant's TLAA for the fatigue crack growth analysis will comply

with the 10 CFR 54.21(c)(1)(i) acceptance criterion for TLAAs.

4.7.3 TLAA in BWRVIP Documents

The BWRVIP documents identify various potential TLAA. The TLAA applicable to JAFNPP are

described below.

4.7.3.1 BWRVlP-05, RPV Circumferential Welds

4.7.3.1.1 Summary of Technical Information in the Application

LRA Section 4.7.3.1 summarizes the BWRVIP-05 RPV circumferential weld evaluation for the

period of extended operation. BWRVIP-05 justifies elimination of reactor vessel circumferential

welds from examination. BWRVIP-74 extends this justification through the period of license

renewal. SER Section 4.2.5 documents the evaluation of the TLAA for this issue.

4.7.3.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3.1, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

LRA Section 4.7.3.1 refers to LRA Section 4.2.5 for the review of the TLAA on the issue of

reactor vessel circumferential welds. SER Section 4.2.5 reports the staffs review of the

information.

4.7.3.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of RPV

circumferential welds in LRA Section A.2.2.1.5. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant's actions to

address RPV circumferential welds is adequate.

4.7.3.1.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that, for RPV circumferential welds, the

analyses 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

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evaluation, as required by 10 CFR 54.21(d).

4.7.3.2 BWRVIP-25, Core Plate

Electric Power Research Institute (EPRI) Topical Report No. TR-1 07284, "BWR Vessel and

Internals Project: Core Plate Inspection and Flaw Evaluation Guidelines (BWRVIP-25)"

(December 1996), provides augmented inspection recommendations and flaw evaluation

guidelines established by the BWRVIP to assure the integrity of core plates in BWR designs.

BWRVIP-25 reports BWRVIP's analysis of the aging effects on BWR core plates and their

components as well as BWRVIP's recommended augmented inspection and flaw evaluation

strategies for managing such aging effects.

4.7.3.2.1 Summary of Technical Information in the Application

LRA Section 4.7.3.2 summarizes the BWRVIP-25 core plate evaluation for the period of extended

operation. The calculation of loss of preload on the core plate rim hold-down bolts is a potential

TLAA per the SER for BWRVIP-25, which calculates the loss of preload for these bolts for 40

years. BWRVIP-25 Appendix B projects this calculation to 60 years, showing that the core

hold-down bolts at JAFNPP will retain at least 81 percent of their preload through the period of

extended operation. Preload of the core plate hold-down bolts is required to prevent lateral

motion of the core plate for plants (like JAFNPP) that have not installed core plate wedges. A

plant-specific calculation must determine minimum bolting requirements to prevent core plate

motion. The applicant commits to a plant-specific calculation prior to the period of extended

operation unless core plate wedges are installed during the remainder of the current licensing

term. Thus, the loss of core plate hold-down bolt preload will be projected for the period of

extended operation.

4.7.3.2.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3.2, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

BWRVIP-25 reports that the analysis of loss of preload in core plate rim hold-down bolts, as a

result of irradiation-assisted stress relaxation, is a potential TLAA for BWR applicants. The staff

approved the BWRVIP-25 inspection and flaw evaluation guidelines in an SE dated

December 7, 2000, concurring in the BWRVIP position on stress relaxation management in BWR

core plate rim hold-down bolts.

The applicant stated that BWRVIP-25 calculates the loss of preload for the core plate rim

hold-down bolts for 40 years operation and projects this calculation to 60 years of operation. The

applicant also stated that the core hold down bolts will retain at least 81 percent of their preload

through the period of extended operation; however, the applicant clarified that preload of the core

plate hold-down bolts is required to prevent lateral motion of the core plate during normal,

transient, seismic, and design-basis accident operating conditions. The applicant stated that a

plant-specific calculation must determine minimum bolting preload requirements to prevent core

plate lateral movement during these conditions. To address this issue, the applicant stated that it

would amend the LRA to include a commitment to a plant-specific calculation prior to the period

of extended operation unless core plate wedges are installed during the remainder of the current

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licensing term.

The design of the core plate does not include core plate wedges or plugs for restraint against

lateral movement during normal operating conditions (including operational transients and

heatups and cooldowns of the reactor), pressure-testing conditions, seismic events, or

design-basis accident conditions. Instead, the core plate design relies on the rim hold-down bolts

to prevent core plate lateral movement during these loading conditions.

During the audit and review, the staff reviewed the LRA and bases documents and determined

that the documentation included no evaluation, calculation, or assessment of the amount of

stress relaxation in the plant's core plate rim hold-down bolts. The applicant admits that stress

relaxation of the core plate rim hold-down bolts is an aging effect needing management or

analysis for the period of extended operation. As the CLB includes no analysis of stress

relaxation of the core plate rim hold-down bolts, the staff concludes that the LRA needs a

commitment to manage stress relaxation in the core plate rim hold-down bolts.

In RAI 4.7.3.2-1 dated January 12, 2007, the staff asked the applicant for the following

information about the core plate rim hold-down bolts:

Provide additional information demonstrating that the requirements specified in the

BWRVIP-25 report, including Appendix B, are applicable to JAFNPP, based on the

following:

a. configuration and geometry of the JAFNPP core plate rim

hold-down bolts,

b. the temperature of the core plate rim hold-down bolts during normal

operation, taking into consideration power uprate conditions, and

c. projected bolt neutron fluence at the end of the period of extended

operation, taking into consideration power uprate conditions.

Include the actual values for bolt temperature and projected bolt neutron fluence in

the above discussion, and explain how it was determined that the effects of

temperature and neutron fluence at the end of the period of extended operation

would result in less than a 20 percent loss of bolt preload.

Provide a detailed description of the methodology and data used at JAFNPP to

perform the above analyses, and include the basis for the stress relaxation curves.

Demonstrate that, under the conditions stated in Scenario 3 of BWRVIP-25,

Appendix A (determination of hold-down bolt loading with no credit for aligner pins

or rim weld), the axial and bending stresses for the hold-down bolts with the mean

and highest loading will not exceed the ASME Code, Section III allowable stresses

for primary membrane and primary membrane plus bending, as a result of a 20

percent reduction in the specified bolt pre-load.

Clearly state the assumptions on which this analysis is based, taking into

consideration the fact that the approach recommended in Appendix A of

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BWRVIP-25 is based on an elastic finite element analysis of the core plate and

hold-down bolts.

In its response dated February 12, 2007, the applicant amended the LRA and stated that, in lieu

of responding to the specific request in RAI 4.7.3.2-1, Commitment No. 23 (JAFP-07-0019,

February 1, 2007) on the LRA addresses the structural integrity of the core plate against lateral

movement. The applicant amended the LRA and Commitment No. 23 in its response to

RAI 4.7.3.2-1 dated April 7, 2007. Commitment No. 23 will require the following actions to ensure

the structural integrity of the core plate against lateral movement during the period of extended

operation:

• Enhance the BWR Vessel Internals Program with inspections of the core plate rim

hold-down bolts.

* LRA Section A.2.2.7 is revised to add that the applicant will

1. Install core plate wedges prior to the period of extended operation or

2. Complete a plant-specific analysis to determine acceptance criteria for

continued inspection of core plate rim hold-down bolting in accordance with

BWRVIP-25 and submit the inspection plan, along with the acceptance criteria and

justification for the plan, two years prior to the period of extended operation for

review and approval or

3. Inspect core plate rim hold-down bolts in accordance with ASME Code

Section XI or with a staff-approved version of BWRVIP-25.

If the applicant selects Option 2, the analysis to determine acceptance criteria will

address the information requested in RAIs 3.1.2-2A and 4.7.3.2-1.

The staff reviewed the applicant's commitment and noted that under the current design the core

plate rim hold-down bolts serve as structural components maintaining core plate integrity against

lateral movement. If the applicant selects Option 1 of Commitment No. 23, the installation of core

plate wedges will replace the core plate rim hold-down bolts in maintaining core plate structural

integrity against lateral movement during the period of extended operation. This maintenance is

in accordance with the options of BWRVIP-25 and acceptable. If it selects Option 2, the applicant

will: (1) complete a plant-specific analysis in accordance with BWRVIP-25 bolt loading analysis

criteria to establish the number of core plate rim hold-down bolts needed to maintain core plate

structural integrity against lateral movement, (2) submit the inspection plan for the core plate rim

hold-down bolts and the technical bases ( i.e., justification and acceptance criteria) for the plan

for review and approval. This option is acceptable because the staff has approved the BWRVIP

criteria for plant-specific loading analyses of BWR core plate rim hold-down bolts in the staff SE

dated December 7, 2000, and because the inspection plan for the core plate rim hold-down bolts

will be submitted to the staff for review and approval at least two years prior to the period of

extended operation and justified based on the results of the plant-specific loading analysis.

Based on this assessment, the staff concludes that Commitment No. 23 provides an acceptable

basis for managing the effect of stress relaxation of the core plate rim hold-down bolts and core

plate integrity during the period of extended operation and for accepting the TLAA on

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BWRVIP-25 in accordance with the 10 CFR 54.21(c)(1)(iii) TLAA acceptance criterion.

4.7.3.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

core plate in LRA Section A.2.2.7. As reported in SER Section 4.7.3.2.2, the applicant placed

Commitment No. 23 on the LRA for assurance that stress relaxation of the core plate rim

hold-down bolts would be managed during the period of extended operation in accordance with

10 CFR 54.21(c)(1 )(iii) or that, as an alternative to inspection of the bolts, the plant would be

modified by wedges installed in the core plate design as an alternative means of maintaining core

plate structural integrity in lieu of the core plate rim hold-down bolts during the period of extended

operation. On the basis of its review of the UFSAR supplement, as amended by Commitment

No. 23, the staff concludes that the summary description of the applicant's actions to address the

core plate is adequate.

4.7.3.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated by Commitment No. 23, pursuant to 10 CFR 54.21(c)(1 )(ii), that core plate

analyses have been projected to the end of the period of extended operation. The staff also

concludes that the UFSAR supplement, with Commitment No. 23, contains an appropriate

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.3.3 BWRVIP-38, Shroud Support

EPRI Topical Report No. TR-1 08823, "BWR Vessel and Internals Project: BWR Shroud Support

Inspection and Flaw Evaluation Guidelines (BWRVIP-38)" (September 1997), provides

augmented inspection recommendations and flaw evaluation guidelines established by the

BWRVIP for core shroud supports in BWR designs. BWRVIP-38 reports in Section B.4,

Appendix B, the impact of license renewal on metal fatigue assessments for BWR RPV core

shroud support components. In this report, the BWRVIP stated that metal fatigue assessments

for BWR RPV core shroud support components may be potential 10 CFR 54.3 TLAAs. The staff

approved BWRVIP-38 in an SE dated March 1, 2001.

4.7.3.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3.3 summarizes the BWRVIP-38 shroud support evaluation for the period of

extended operation. The BWRVIP-38 fatigue analysis of the shroud support is considered a

TLAA. The shroud support is included in the 60-year fatigue analysis and shows a 0.9 CUF. This

analysis remains valid for the period of extended operation.

4.7.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3.3, to verify pursuant to 10 CFR 54.21(c)(1)(i), that the

analyses remain valid for the period of extended operation.

BWRVIP-38 Section B.4, Appendix B, reports that metal fatigue of a BWR core shroud support

should be treated as a TLAA if the CLB includes a metal fatigue analysis for the component.

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The applicant stated that the CUF-based metal fatigue analysis for the core shroud support

meets the 10 CFR 54.3 definition of a TLAA. LRA Sections 4.3.1 and 4.3.1.1 addresses the core

shroud support metal fatigue assessment in accordance with the BWRVIP-38 determination and

is acceptable. SER Section 4.3.1.2 reports the staff's evaluation and basis for accepting the metal

fatigue assessment for the core shroud support.

4.7.3.3.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

shroud support in LRA Section A.2.2.8. The staff determined that, pending acceptable resolution

of RAI 4.3.1-1, the UFSAR Supplement summary description in LRA Section A.2.2.8 is consistent

with this determination and acceptable. On the basis of its review of the UFSAR supplement, the

staff concludesthat the summary description of the applicant's actions to address the shroud

support is adequate.

4.7.3.3.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the shroud support analyses remain valid

for the period of extended operation. The staff also concludes that the UFSAR supplement,

pending acceptable resolution of RAI 4.3.1-1, contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.3.4 BWRVIP-47-A, Lower Plenum

EPRI Topical Report No. TR-108727, "BWR Vessel and Internals Project:

BWR Lower Plenum Inspection and Flaw Evaluation Guidelines (BWRVIP-47)"

(December 1997), provides augmented inspection recommendations and flaw evaluation

guidelines established by the BWRVIP for RPV lower plenum components in BWR designs.

BWRVIP-47 Section B.4, Appendix B, assesses the impact of license renewal on the metal

fatigue assessments for BWR RPV lower plenum components. In this report, the BWRVIP stated

that metal fatigue of BWR RPV lower plenum may be a potential TLAA in accordance with

10 CFR 54.3.

4.7.3.4.1 Summary of Technical Information in the Application

LRA Section 4.7.3.4 summarizes the BWRVIP-47-A lower plenum evaluation for the period of

extended operation. The BWRVIP-47 fatigue analysis of the lower plenum pressure boundary

components is considered a TLAA. The bottom head, shroud support, and control rod drive

penetrations in the lower plenum are included in the 60-year fatigue analysis. CUF values are

0.03, 0.90, and 0.0234 respectively. This analysis remains valid for the period of extended

operation.

4.7.3.4.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3.4, to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

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BWRVIP-47 Section B.4, Appendix B, reports that metal fatigue assessments of lower plenum

areas should be treated as TLAAs if the CLB includes specific metal fatigue analyses for the

lower plenum components. The applicant stated that the CLB includes CUF-based metal fatigue

analyses for the RPV bottom head, core shroud support, and CRD penetrations and that these

analyses meet the 10 CFR 54.3 definition of a TLAA. The applicant's determination is in

accordance with BWRVIP-47 criteria for treating metal fatigue analyses of lower plenum

components as potential TLAAs for the LRA and acceptable. LRA Sections 4.3.1 and 4.3.1.1

describe the metal fatigue assessment for the RPV bottom head, core shroud support, and CRD

penetrations. SER Section 4.3.1.2 reports the staff's evaluation and basis for acceptance of the

metal fatigue assessments for the RPV bottom head, core shroud support, and CRD

penetrations.

4.7.3.4.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

lower plenum in LRA Section A.2.2.9. On the basis of its review of the UFSAR supplement, and

the applicant's response to RAI 4.3.1-1 dated August 14, 2007, the staff concludes that the

summary description of the applicant's actions to address the lower plenum is adequate.

4.7.3.4.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the lower plenum analyses remain valid for

the period of extended operation. The staff also concludes that the UFSAR supplement contains

an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.3.5 BWRVIP-74, Reactor Pressure Vessel

4.7.3.5.1 Summary of Technical Information in the Application

LRA Section 4.7.3.5 summarizes the BWRVIP-74 RPV evaluation for the period of extended

operation. BWRVIP-74 and its SER address the following four TLAAs:

(1) P-T Curve Analyses - The SER concludes "a set of P-T curves should be developed for

the heat-up and cool-down operating conditions in the plant at a given EFPY in the LR

period." LRA Section 4.2.2 addresses the JAFNPP P-T curves.

(2) Fatigue - The SER states that license renewal applicants should not rely solely on the

BWRVIP-74-A analysis but should verify that the number of cycles assumed in the original

fatigue design is conservative. LRA Section 4.3.1 addresses RPV fatigue. The SER also

states that staff concerns on environmental fatigue are not resolved and that each

applicant should address environmental fatigue for the components covered by

BWRVIP-74-A. LRA Section 4.3.3 addresses environmentally-assisted fatigue.

(3) Equivalent Margins Analysis for RPV Materials with Charpy USE Less than 50 ft-lb -

BWRVIP-74-A states that the percentage reductions in Charpy USE for beltline materials

are less than those specified for limiting BWR/3-6 plates and non-Linde 80 submerged arc

welds. LRA Section 4.2.3 addresses Charpy USE for RPV materials.

(4) Material Evaluation for Exempting RPV Circumferential Welds from Inspection - LRA

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Section 4.2.5 addresses RPV circumferential weld inspection relief.

4.7.3.5.2 Staff Evaluation

The staff determined that the applicant has developed a set of P-T curves. The applicant

committed to submit additional P-T curves prior to the period of extended operation. SER

Section 4.2.2 reports the staff evaluation of the P-T curves.

The staff determined that LRA Section 4.3.1 and LRA Table 4.3-1 include plant-specific metal

fatigue analyses for the Class 1 RPV and RPV internal components and metal fatigue TLAAs and

60-year CUF values for these components. SER Section 4.3.1 reports the staff's evaluation of the

metal fatigue TLAAs for these components. The staff also determined that the applicant had

calculated plant-specific environmentally-impacted CUFs for the Class 1 components analyzed in

NUREG-6260 and BWRVIP-74A and had provided the environmentally-impacted fatigue TLAA

for these components in LRA Section 4.3.3 and LRA Table 4.3-3. SER Section 4.3.3 reports the

staff's evaluation of the environmentally-impacted metal fatigue TLAAs for these components.

LRA Section 4.2.3 addresses the percent reductions in CvUSE. SER Section 4.2.3 reports the

staff's evaluation of the information.

The staff evaluated the TLAA for relief from ISI of the RPV circumferential shell welds as reported

in SER Section 4.2.5.

4.7.3.5.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

reactor pressure vessel in LRA Section A.2.2.1. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant's actions to

address the reactor pressure vessel is adequate.

4.7.3.5.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, in compliance with 10 CFR 54.21(c)(1)(ii), that the TLAA items addressed in

BWRVIP-74-A 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).

4.7.3.6 BWRWP-76, Core Shroud

EPRI Topical Report No. TR-1 14232, "BWR Vessel and Internals Project, BWR Lower Plenum

Inspection and Flaw Evaluation Guidelines (BWRVIP-47)" (November 1999), provides augmented

inspection recommendations and flaw evaluation guidelines established by the BWRVIP for core

shroud and core shroud repair assembly components in BWR designs. BWRVIP-74 Section K.4,

Appendix K, assesses the impact of license renewal on metal fatigue assessments for BWR core

shroud and core shroud repair assembly components. In this report, the BWRVIP stated that

BWR core shroud and core shroud repair assembly component metal fatigue analyses may be

potential 10 CFR 54.3 TLAAs. The staff approved the BWRVIP recommended guidelines for

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augmented inspections and analyses of BWR core shroud and core shroud repair assembly

components in an SE dated July 27, 2006.

4.7.3.6.1 Summary of Technical Information in the Application

LRA Section 4.7.3.6 summarizes the BWRVIP-76 core shroud evaluation for the period of

extended operation. BWRVIP-76 Appendix K states that plant-specific analyses for shroud

fatigue are reviewed for TLAAs. Review of the reactor vessel and internals design basis

documents found no fatigue analysis nor CUF calculation for the shroud itself. Fatigue analyses

(CUF calculations) were found for the shroud support and the shroud tie rod assemblies, and

these are addressed in LRA Section 4.3.1.2. This TLAA is projected through the period of

extended operation.

4.7.3.6.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3.6, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

In BWRVIP-76, the BWRVIP concluded that metal fatigue analyses for core shroud and core

shroud repair assembly components should be treated as TLAAs if the CLB includes

corresponding plant-specific fatigue analyses for these components.

The applicant stated that the CUF analysis for the core shroud tie rod repair assemblies conforms

to the 10 CFR 54.3 definition of a TLAA. This analysis is in accordance with the BWRVIP-76

determination and acceptable. LRA Sections 4.3.1 and 4.3.1.2 describe the applicant's evaluation

of its TLAA for the core shroud tie repair assemblies. SER Section 4.3.1.2 reports the staff's

basis for acceptance of the 60-year CUF value for core shroud tie rod repair assemblies.

4.7.3.6.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

core shroud in LRA Section A.2.2.2.1. On the basis of its review of the UFSAR supplement, the

staff concludes that the summary description of the applicant's actions to address the core

shroud is adequate.

4.7.3.6.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the core shroud analyses 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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4.7.4 Assessment of Plant-Specific Fatigue Flaw Growth and Fracture Mechanics

Evaluations

4.7.4.1 Summary of Technical Information in the Application

LRA Tables 3.1.2-1, 3.1.2-2, and 3.1.2-3 show TLAA - metal fatigue for managing

fatigue-induced cracking for many Class 1 components (e.g., reactor vessel internal attachments

and welds, the incore monitor housing bolting, CRD housings, CRD stub tubes, the CRD return

line, the reactor vessel (the shell, upper and bottom head and the closure flange), and the reactor

vessel nozzles (including safe ends and thermal sleeves)) for various piping and instrumentation

connections.

4.7.4.2 Staff Evaluation

SRP-LR Section 4.3 provides metal fatigue analysis guidance based on the CUF approach as

specified in ASME Code Section III. LRA Section 4.3 addresses the requirements of the ASME

Code Section III fatigue calculations. SER Section 4.0 reports the staff's evaluation of the ASME

Code Section III fatigue calculations of LRA Section 4.3.

The ASME Code Section III fatigue analysis assumes no crack in the components; however,

during operation, ASME Code Section XI allows flaws of certain sizes to remain in service. The

staff believes that, as part of the TLAA, an evaluation of the known flaw in the affected

component also should assess the stability of the final crack size at the end of the period of

extended operation. The flaw evaluation should demonstrate that the affected component has

sufficient fracture toughness to resist rapid crack propagation for the period of extended

operation. The method for the flaw evaluation should follow ASME Code Section Xl.

LRA Section 4.3 describes the flaw evaluation without much detail; therefore, in RAI 3.1.2-1 dated

April 2, 2007, the staff asked the applicant (a) to indicate which Class 1 components in

Table 3.1.2-1 contain indications or flaws which remained in service based on the acceptance

criteria of ASME Code Section XI, (b) to describe the flaw evaluations (e.g., procedures and

assumptions) of the affected components in accordance with ASME Code Section Xl, (c) to state

the number of years assumed in the fatigue crack growth analysis, and (d) to demonstrate

whether the affected components are acceptable for the period of extended operation.

In its response dated April 24, 2007, the applicant stated that it had studied the analyses of flaws

detected during ISIs. The only TLAA found during this study was the fatigue analysis of the core

shroud hardware installed to repair core shroud cracking. LRA Section 4.3.1.2 addresses this

TLAA with other fatigue TLAAs. The applicant detected indications in the following eight

components:

(1) Torus Shell

In a letter dated April 24, 2007, the applicant stated that the flaw in the torus shell had

been removed, no longer exists, and has no flaw growth analysis. The staff notes that the

structural integrity of the torus must satisfy ASME Code Section XI, Subarticle IWE. As

part of the torus repair, the applicant requested relief from ASME Code Section XI,

Subarticle IWE, requirements for pressure testing of the torus shell. By letter dated

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July 8, 2005, the staff authorized the relief request. Information Notice 2006-01 addressed

the torus shell cracking. The staff finds that the torus shell cracking has been repaired in

accordance with ASME Code Section Xl, Subarticle IWE; therefore, no flaw growth

calculation is needed. In addition, the applicant will inspect the torus periodically in

accordance with ASME Code Section XI, Subsection IWE. Disposition or analysis of any

crack detected will be in accordance with Subarticle IWE. The staff finds the torus

adequately managed for metal fatigue to maintain intended functions for the period of

extended operation.

(2) RHR Shutdown Cooling Line

In a letter dated April 24, 2007, the applicant stated that the flaw in the RHR shutdown

cooling line had been removed, no longer exists, and has no flaw growth analysis. By

letter dated August 9, 2005, the staff approved a temporary non-ASME Code repair of the

subject piping. In the subsequent refueling outage, the applicant permanently repaired the

pipe in accordance with ASME Code Section XI, Subarticle IWC-4000. The RHR

shutdown cooling piping is classified as an ASME Class 2 component. The examination

and repair of the pipe will follow the requirements of ASME Code Section XI, Subarticle

IWC. Disposition or analysis of any crack detected in the shutdown cooling line will be in

accordance with Subarticle IWC. Therefore, the staff finds the RHR shutdown cooling line

adequately managed for metal fatigue to maintain intended functions for the period of

extended operation.

(3) Steam Dryer

In a letter dated April 24, 2007, the applicant stated that the steam dryer is a non-ASME

Code, non-pressure boundary part. The flaws were found during inspections

recommended by the BWRVIP as implemented through the ISI Program. The applicant

evaluated the indications using BWRVIP-139, not ASME Code Section XI, guidance. One

flaw was repaired during Refueling Outage 17 in 2006 and the other was within

acceptance criteria for continued service. Subsequent inspection revealed that the

remaining flaw remains within acceptance criteria for continued service. The applicant

stated further that it will continue to monitor the flaw and to manage the effects of aging

on the steam dryer through the period of extended operation in accordance with BWRVIP

guidelines.

SER Section 3.0.3.2.7 reports in detail many issues related to the steam dryer. This

review of the management of cracks in the steam dryer to the end of the period of

extended operation is limited. The staff agrees with the applicant that the steam dryer is

not an ASME Code or pressure boundary component and that the ASME Code

requirements are not applicable. The applicant has used BWRVIP-139 to dispose of the

cracks found in the steam dryer; however, the staff has not approved BWRVIP-1 39. After

approval, the staff expects BWRVIP-139 to be revised to include any additional

modifications or conditions that the staff may impose on that report and the applicant to

follow the guidance in the approved BWRVIP-139 in the future. The staff finds the steam

dryer adequately managed for metal fatigue to maintain intended functions for the period

of extended operation.

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(4) Core Spray Line (Inside The Vessel)

In a letter dated April 24, 2007, the applicant stated that it had detected and has

monitored two indications on the "B" loop core spray line inside the reactor vessel during

inspections recommended by the BWRVIP.

According to the applicant, the first crack was discovered in 1988 between the core spray

nozzle and core shroud and repaired with a clam shell sleeve, which is not an ASME Code

repair and involves no flaw growth analysis. As the "new" pressure boundary for the

cracked weld the clam shell sleeve essentially removes the existing flaw from service. The

structural integrity of the flawed weld is not credited to demonstrate acceptability for

continued service. The applicant inspected the clam shell sleeve repair as part of the

BWRVIP Inspection Program.for structural integrity and detected no cracking. The core

spray piping inside the reactor vessel is not ASME Code piping.

The applicant detected the second indication at weld CSB-12 (P3) during Refueling

Outage 14 in 2000. There was no change in the length of this indication between

Refueling Outage 14 in 2000 and Refueling Outage 15 in 2002. The 2002 inspections and

more detailed inspections in 2006 indicate that the indication is a scratch rather than a

crack. As this indication is not a flaw, no repair was required.

The applicant stated further that it will continue to manage cracking of the core spray line,

including these indications, under the BWRVIP per BWRVIP-1 8A guidelines through the

period of extended operation.

The staff finds that the applicant has inspected the clam shell sleeve repair and has found

no cracking. The applicant is managing and will manage the core spray line based on the

staff-approved BWRVIP-1 8A Report. The staff finds the core spray line inside the reactor

vessel adequately managed for metal fatigue to maintain intended functions for the period

of extended operation.

(5) Core Shroud Cracking

In a letter dated April 24, 2007, the applicant stated that it had inspected the core shroud

per BWRVIP-76 guidelines during Refueling Outage 12 in 1996 and Refueling Outage 13

in 1998 and detected crack-like indications for vertical welds SV5A, SV5B, SV6A, SV6B

and horizontal weld H4. Re-inspection intervals for the vertical welds are determined

based on flaw growth analyses in accordance with BWRVIP guidelines.

According to the applicant, a shroud tie rod repair was installed to maintain shroud

integrity if the horizontal welds fail; consequently, structural integrity of the shroud does

not rely on the horizontal welds. The shroud repair (tie rods) is of a design different from

that installed at the Hatch Nuclear Power Plant. The applicant stated that, therefore, the

bracket of the shroud tie rods does not require repair to preclude the cracking

experienced at the Hatch plant. The applicant inspects tie rods routinely as specified in

BWRVIP-76 Program requirements. The ten tie rods were inspected during Refueling

Outage 17 in 2006 with no degradation noted.

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The staff finds that the applicant has followed the BWRVIP-76 requirements to inspect

core shroud tie rods periodically; therefore, the staff finds the core shroud and the tie rods

adequately managed for metal fatigue to maintain intended functions for the period of

extended operation. The staff has not approved BWRVIP-76. After approval, the staff

expects BWRVIP-76 to be revised to include any additional requirements that the staff

may impose and the applicant to follow the approved BWRVIP-76 guidance. SER

Section 4.3.1 reports the additional evaluation of the core shroud and tie rods.

(6) Main Steam Nozzle

In a letter dated April 24, 2007, the applicant stated that it had inspected main steam

nozzles ultrasonically in 1988 as part of the ISI Program and detected a subsurface

indication on main steam nozzle N3C. Re-inspection of the N3C nozzle in 1989 and 1990

revealed no discernable change in its size. The applicant believes that this indication is a

minor weld defect accepted by radiography during plant construction. The applicant stated

further that this indication is acceptable per ASME Code Section XI, Subsection

IWB-3610(b), and no flaw growth analysis is required. The applicant will continue to

monitor this indication through the ISI Program.

The staff finds that the applicant has followed ASME Code Section XI for inspection of the

main steam nozzles and disposition of the crack. The staff confirmed that the size of the

indication detected in 1988 has not changed in the successive inspections in 1989 and

1990 and that the applicant has a program for monitoring Nozzle N3C and other main

steam nozzles in accordance with ASME Code Section Xl. Therefore, the staff finds the

main steam nozzles adequately managed for metal fatigue to maintain intended functions

for the period of extended operation.

(7) CRD Return Line Nozzle to End Cap Weld

In a letter dated April 24, 2007, the applicant stated that in 2000 it had discovered a crack

on the inside diameter of the weld between the CRD return line nozzle and the end cap.

The applicant repaired the CRD nozzle cap using a weld overlay. JAFNPP Relief Request

RR-26 requested relief from 10 CFR 50.55a(c)(3) repair criteria for the CRD return nozzle

cap. This relief request cited ASME Code Section Xl, Code Case N-504-1, "Alternative

Rules for Repair of Class 1, 2, and 3 Austenitic Stainless Steel Piping, Section XI, Division

1 Weld Overlays to Address IGSCC Indications." ASME Code Section XI, Code Case

N-504-1, Section (g)(2), states that an evaluation of the repair

shall demonstrate that the requirements of IWB-3640 from the 1983

Edition and Addenda [of the ASME Code, Section X1], are satisfied

for the design life of the repair, considering potential flaw growth

due to fatigue and the mechanism believed to have caused the flaw.

The flaw growth evaluation shall be performed in accordance with

Appendix C [of the ASME Code, Section XI].

The overlay carries the structural load carried previously by the flawed weld. The overlay

analysis conservatively assumes that the underlying flaw is 100 percent through-wall and

360 0 around the pipe (i.e., complete separation of the underlying pipe as described in

NUREG-0313 Section 4.4.1). The applicant assumed the flaw would grow 100 percent

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through the pipe wall thickness and thus took no credit for structural integrity of the

underlying weld. Fatigue crack growth analysis is not needed because the design

assumption for the weld overlay of the affected CRD return line cap weld is that the flaw

will grow 100 percent through-wall.

The staff approved the relief request (RR-26) and on October 26, 2000, issued an SE

concluding that the proposed alternative reasonably assures structural and pressure

boundary integrity of the capped N9 nozzle of the reactor vessel and, thus, acceptable

quality and safety.

The staff finds that the applicant has repaired the crack in the weld joining the CRD return

line nozzle and the end cap based on the staff-approved weld overlay repair. The staff

agrees with the applicant that a flaw growth analysis for the CRD crack is not needed

because the weld overlay design assumption is that the crack- is 100 percent through the

pipe wall thickness and 360 0 around the pipe. The applicant will manage the CRD nozzles

according to BWRVIP-75-A, which the staff has approved; therefore, the staff finds the

CRD return line adequately managed for metal fatigue to maintain intended functions for

the period of extended operation.

(8) Weld Overlays to Address Intergranular Stress Corrosion Cracking (IGSCC) Indications

In a letter dated April 24, 2007, the applicant stated that it had applied 21 weld overlays to

recirculation system piping and two overlays to jet pump instrumentation piping to address

flaw indications detected during inspections performed for the IGSCC Program.

The applicant stated that the overlays were designed and installed in accordance with

GL 88-01, NUREG-0313, Revision 2, and ASME Code Section XI. In particular,

NUREG-0313 Section 4.4.1 suggests that the overlay be designed assuming the original

crack was 100 percent through-wall of the pipe thickness with a length of 360 0 around the

pipe circumference. The overlay then is designed large enough to assume all the loads

previously borne by the flawed weld. There is no flaw growth analysis of the underlying

flaw because the assumed flaw in the weld overlay design is the worst case.

The applicant stated further that, because the overlays are sized based on complete weld

failure despite compression of the weld to prevent future crack growth (compressive

residual stress minimizes future crack growth), the design is conservative and the affected

components are acceptable for the period of extended operation. Confirmatory

inspections of the weld overlays in the period of extended operation will be as specified by

BWRVIP-75-A Section 3.5.1.1 guidelines.

The staff finds that the applicant has followed the guidance of NUREG-0313, Revision 2 in

applying 21 weld overlays to recirculation system piping and two overlays to jet pump

instrumentation piping. In addition, the applicant will follow the staff- approved

BWRVIP-75-A guidance to monitor the integrity of the affected components. The staff

finds the recirculation system and jet pump instrumentation piping adequately managed

for metal fatigue to maintain intended functions for the period of extended operation.

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4.7.4.3 UFSAR Supplement

The staff has provided its basis for concluding that the flaw evaluations and fracture mechanics

evaluations evaluated by the staff as reported in SER Section 4.7.4.2 do not meet the 10 CFR

54.3 definition of a TLAA; therefore, the staff concludes that LRA Appendix A need not include

any UFSAR Supplement summary descriptions for these flaw evaluations and fracture mechanics

evaluations.

4.7.4.4 Conclusion

The staff evaluated the fracture mechanics evaluations and flaw evaluations that the applicant

has indicated as potential TLAAs for the LRA. Based on the evaluation reported in SER

Section 4.7.4.2, the staff concludes that these flaw evaluations and fracture mechanics

evaluations do not meet the 10 CFR 54.3 definition of a TLAA. The staff also concludes that LRA

Appendix A need not include any UFSAR Supplement summary descriptions for these flaw

evaluations and fracture mechanics evaluations as required by 10 CFR 54.21(d) if determined to

be TLAAs for the LRA.

4.8 Conclusion for Time-Limited Aging Analyses

The staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On the basis

of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, as

defined in 10 CFR 54.3 and that the applicant has demonstrated that: (1) the TLAAs will remain

valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i); (2) the TLAAs

have been projected to the end of the period of extended operation, as required by

10 CFR 54.21(c)(1)(ii); or (3) that the effects of aging on the intended function(s) will be

adequately managed for the period of extended operation, as required by 10 CFR 54.21 (c)(1 )(iii).

The staff also reviewed the 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 any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are in

accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

4-66
SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

In accordance with Title 10, Part 54, of the Code of Federal Regulations, the Advisory Committee

on Reactor Safeguards (ACRS) will review the license renewal application (LRA) for James A.

FitzPatrick Nuclear Power Plant. The ACRS Subcommittee on Plant License Renewal will

continue its detailed review of the LRA after this safety evaluation report (SER) is issued. Entergy

Nuclear Operations, Inc. (the applicant) and the staff of the United States (US) Nuclear

Regulatory Commission (NRC) (the staff),will meet with the subcommittee and the full committee

to :discuss issues associated with the review of the LRA.

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal of

operating license for James A. FitzPatrick -Nuclear Power Plant on July 31, 2007. On September

5, 2007, the applicant presented its license renewal application, and the staff presented its review

findings to the ACRS Plant License Renewal Subcommittee. The staff reviewed the applicant's

comments on the SER and completed its review of the license renewal application. The staff's

evaluation is documented in an SER that was issued by letter dated January 24, 2008.

During the 550th meeting of the ACRS on March 6, 2008, the ACRS completed its review of the

FitzPatrick license renewal application and the NRC staff's SER. The ACRS documented its

finding in a letter to the Commission dated March 20, 2008. A copy of this letter is provided on the

following pages of this SER Section.

5-1

"0 UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

WASHINGTON, DC 20555 - 0001

March 20, 2008

The Honorable Dale E. Klein

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE JAMES A. FITZPATRICK NUCLEAR POWER PLANT

Dear Chairman Klein:

During the 550t1 meeting of the Advisory Committee on Reactor Safeguards, March 6-7, 2008, we

completed our review of the license renewal application for the James A. FitzPatrick Nuclear

Power Plant (JAFNPP) and the final Safety Evaluation Report (SER) prepared by the NRC staff.

Our Plant License Renewal Subcommittee also reviewed this matter during a meeting on

September 5, 2007. During these reviews, we had the benefit of discussions with representatives

of the NRC staff and the applicant, Entergy Nuclear Operations, Inc., (ENO). We also had the

benefit of the documents referenced. This report fulfills the requirements of 10 CFR 54.25 that

the ACRS review and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage agerelated degradation provide reasonable assurance that JAFNPP can be operated

in accordance with its current licensing basis for the period of extended operation

without undue risk to the health and safety of the public.

2. The ENO application for renewal of the operating license of JAFNPP should be

approved.

BACKGROUND AND DISCUSSION

JAFNPP is a General Electric boiling water reactor-4 (BWR-4) with a Mark-1 containment. The

current power rating of 2536 MWt includes a 4 percent power uprate that was implemented in

1996. ENO requested renewal of the JAFNPP operating license for 20 years beyond the current

license term, which expires on October 17, 2014.

In the final SER, the staff documented its review of the license renewal application and other

5-3
information submitted by ENO and obtained during the audits and inspections conducted at the

plant site. The staff reviewed the completeness of the applicant's identification of structures,

systems, and components (SSCs) that are within the scope of license renewal; the integrated

plant assessment process; the applicant's identification of the plausible aging mechanisms

associated with passive, long-lived components; the adequacy of the applicant's Aging

Management Programs (AMPs); and the identification and assessment of time-limited aging

analyses (TLAAs) requiring review.

In the JAFNPP license renewal application, ENO identified the SSCs that fall within the scope of

license renewal and performed an aging management review for these SSCs. Based on this

review, the applicant will implement 36 AMPs for license renewal including existing, enhanced,

and new programs.

The JAFNPP application either demonstrates consistency with the Generic Aging Lessons

Learned (GALL) Report or documents deviations to the specified approaches in this report.

The JAFNPP application includes a significant number of exceptions to the approaches specified

in the GALL Report. We reviewed these exceptions and agree with the staff that they are

acceptable. Other recent license renewal applications have exhibited a similar trend toward an

increasing number of exceptions to the GALL Report. The staff agrees that future updates of the

GALL Report should incorporate alternative approaches which are used by the industry and have

been approved by the staff. This will reduce the number of exceptions to the GALL Report in

future applications and will facilitate the staff review.

The staff conducted license renewal audits and site inspections. The audits verified the

appropriateness of the scoping and screening methodology, AMPs, aging management review,

and TLAAs. The site inspections verified that the license renewal requirements are appropriately

implemented. Based on the audits and inspections, the staff concludes in the SER that the

proposed activities will reasonably manage the effects of aging of SSCs identified in the

application and that the intended functions of these SSCs will be maintained during the period of

extended operation. We agree with this conclusion.

During our meetings with the staff and the applicant, we reviewed the physical condition of the

drywell shell of the Mark 1 containment of JAFNPP and the associated AMPs. Aging of the

drywell shell and torus of JAFNPP will be managed through the use of the American Society of

Mechanical Engineers (ASME) Code Section XI, Subsection IWE Program. This program

provides for inspection of primary containment components and the containment vacuum breaker

system piping and components. The aging effects are managed by periodic sampling

inspections, evaluation of inspection results, and repair of any significant degradation. Drywell

monitoring includes periodic boroscopic inspections of the sand cushion area, visual inspection of

the interior drywell caulk seal, and inspection of the drywell interior coating system. The JAFNPP

drywell design minimizes the potential for water intrusion and includes an alarm system that

annunciates in the control room if leakage from the refueling cavity occurs during refueling. The

applicant stated that the plant has not experienced occurrences of leakage through the refueling

bellows into the area monitored by the air gap leakage detection system. The applicant stated,

and the NRC inspectors confirmed, that the JAFNPP drywell shell is in good physical condition.

In June 2005, a through-wall leak in the JAFNPP torus shell was identified. The leak was due to

a 4.5 inch crack located in the same bay as the high-pressure coolant injection (HPCI) steam

exhaust discharge pipe. The root cause of the flaw was vibration fatigue from HPCI steam

5-4
condensation oscillation loading. Follow-up torus inspections identified similar flaws in two other

locations in the same bay. Corrective action included repair of the flaws and the installation of a

HPCI steam exhaust sparger assembly that directs steamflow away from the torus shell.

The sparger significantly reduces steam condensation oscillation loads on the torus shell.

Pitting in the wetted area of the torus shell was identified in 1998 when the torus was drained to

replace the emergency core cooling system suction strainers. Further inspection of the torus

identified pitting in ten areas in four of the 16 torus bays. The pitting occurred at locations that

had experienced some degradation of the original coating. The pitted areas have not been

re-coated. They are considered as leading indicators of torus shell condition and are being

monitored periodically with ultrasonic testing and visual inspection. The staff and the NRC

inspection team reviewed the JAFNPP containment inservice inspection program and concluded

that ENO's program includes appropriate requirements for continued inspection of the torus,

evaluation of observed degradation, and prediction of remaining service life. We concur with this

conclusion.

The applicant identified the systems and components requiring TLAAs and reevaluated them for

the period of extended operation. The staff concluded that the applicant has provided an

adequate list of TLAAs. Further, the staff concluded that in all cases the applicant has met the

requirements of the license renewal rule by demonstrating that the TLAAs will remain valid for the

period of extended operation, or that the TLAAs have been projected to the end of the period of

extended operation, or that the aging effects will be adequately managed for the period of

extended operation. We concur with the staff's conclusion that JAFNPP TLAAs have been

properly identified and that the required criteria will be met for the period of extended operation.

We agree with the staff that there are no issues related to the matters described in

10 CFR 54.29(a)(1) and (a)(2) that preclude renewal of the operating license for JAFNPP.

The programs established and committed to by ENO provide reasonable assurance that JAFNPP

can be operated in accordance with its current licensing basis for the period of extended

operation without undue risk to the health and safety of the public. The ENO application for

renewal of the operating license for JAFNPP should be approved.

Sincerely,

IRA/

William J. Shack,

Chairman

REFERENCES

1. Letter dated July 31, 2006, from P. Dietrich, Entergy Nuclear Operations, Inc. to U.S. Nuclear

Regulatory Commission, transmitting the Application to Renew the Operating License of James

A. FitzPatrick Nuclear Power Plant, (ML062160491).

2. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report, Related to the License

Renewal of James A. FitzPatrick Nuclear Power Plant, " February 2008 (ML080250372).

3. Letter dated June 19, 2007 from N. Le, U.S. Nuclear Regulatory Commission to M. Kansler,

Entergy Nuclear Operations, Inc., transmitting the Audit Summary Report for Plant Aging

5-5
Management Reviews and Programs for the James A. FitzPatrick Nuclear Power Plant on

License Renewal Application, (ML071580049).

4. NRC License Renewal Inspection Report 05000333/2007007, James A. FitzPatrick Nuclear

Power Plant, dated August 2, 2007, (ML072140637).

5. U.S. Nuclear Regulatory Commission, NUREG-1801, Volumes 1 & 2, Revision 1, "Generic

Aging Lessons Learned Report," September 2005.

5-6
SECTION 6

CONCLUSION

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

the license renewal application (LRA) for James A. FitzPatrick Nuclear Power Plant in accordance

with NRC regulations and US NRC Regulatory Guide (NUREG)-1800, Revision 1, "Standard

Review Plan for Review of License Renewal Applications for Nuclear Power Plants," dated

September 2005. Title 10, Section 54.29, of the Code of Federal Regulations (10 CFR 54.29)

sets the standards for issuance of a renewed license.

On the basis of its review of the LRA, the staff 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, are documented in

NUREG-1 437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants

(GELS)," draft Supplement 31, "Generic Environmental Impact Statement for License Renewal of

Nuclear Plants Regarding James A. FitzPatrick Nuclear Power Plant," dated June 2007. The staff

further notes that the Final Supplement 31 was issued on January 18, 2008.

6-1

APPENDIX A

JAFNPP LICENSE RENEWAL COMMITMENTS

During the review of the James A. FitzPatrick Nuclear Power Plant (JAFNPP) license renewal

application (LRA) by the staff of the United States Nuclear Regulatory Commission (NRC) (the

staff), Entergy Nuclear Operations, Inc. (the applicant) made commitments related to aging

management programs (AMPs) to manage aging effects for structures and components. The

following table lists these commitments along with the implementation schedules and sources for

each commitment.

A-1
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

LRA Section Schedule

Implement the Buried Piping and Tanks Inspection Program as A.2.1.1 October 17, 2014 JAFP-06-0109

described in LRA Section B.1.1

B.1.1

2 Enhance the BWR CRD Return Line Nozzle Program to A.2.1.2 October 17, 2014 JAFP-06-0109

examine the CRDRL nozzle-to-vessel weld and the CRDRL

nozzle inside radius section per Section XI Table IWB-2500-1 B.1.2

Category B-D Items B3.90 and B3.100.

3 Enhance the Diesel Fuel Monitoring Program to include A.2.1.9 October 17, 2014 JAFP-06-0109

periodic draining, cleaning, visual inspections, and ultrasonic

measurement of the bottom surfaces of the fire pump diesel B.1.9

fuel oil tanks, EDG day tanks, and EDG fuel oil storage tanks to

ensure that significant degradation is not occurring.

Enhance the Diesel Fuel Monitoring Program to specify

acceptance criteria for UT measurements of diesel generator

fuel storage tanks within the scope of this program.

4 Enhance the External Surfaces Monitoring Program guidance A.2.1.11 October 17, 2014 JAFP-06-0109

documents to include periodic inspections of systems in scope

and subject to aging management review for license renewal in B.1.11

accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections

shall include areas surrounding the subject systems to identify

hazards to those systems. Inspections of nearby systems that

could impact the subject systems will include SSCs that are in

scope and subject to aging management review for license

renewal in accordance with 10 CFR 54.4(a)(2).

A-2
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

LRA Section Schedule

5 Enhance the Fire Protection Program to inspect fire barrier A.2.1.13 October 17, 2014 JAFP-06-0109

walls, ceilings, and floors at least once every refueling outage.

Inspection results will be acceptable if there are no visual B.1.13.1

indications of degradation such as cracks, holes, spalling, or

gouges.

Enhance the Fire Protection Program to inspect at least one

seal of each type every 24 months.

6 Enhance the Fire Water Program to include inspection of hose A.2.1.14 October 17, 2014 JAFP-06-0109

reels for corrosion. Acceptance criteria will be enhanced to

verify no significant corrosion. B.1.13.2

Enhance Fire Water Program to include visual inspection of

spray and sprinkler system internals for evidence of corrosion.

Acceptance criteria will be enhanced to verify no significant

corrosion.

Enhance Fire Water Program to include that a sample of

sprinkler heads will be inspected using guidance of NFPA 25

(2002 Edition) Section 5.3.1.1.1. NFPA 25 also contains

guidance to repeat sampling every 10 years after initial field

service testing.

Enhance Fire Water Program to include that wall thickness

evaluations of fire water piping will be performed on system

components using non-intrusive techniques to identify evidence

of loss of material due to corrosion. These inspections will be

performed before the end of the current operating term and at

intervals thereafter during the period of extended operation.

Results of the initial evaluations will be used to determine the

appropriate inspection interval to ensure aging effects are

identified prior to loss of intended function.

A-3
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

LRA Section Schedule

7 Implement the Heat Exchanger Monitoring Program as A.2.1.16 October 17, 2014 JAFP-06-0109

described in LRA Section B.1.15.

B.1.15

8 Implement the Metal-Enclosed Bus Inspection Program as A.2.1.19 October 17, 2014 JAFP-06-0109

described in LRA Section B.1.17.

B.1.17

9 Implement the Non-EQ Instrumentation Circuits Review A.2.1.20 October 17, 2014 JAFP-06-0109

Program as described in LRA Section B.1.18.

B.1.18

10 Implement the Non-EQ Insulated Cables and Connections A.2.1.21 October 17, 2014 JAFP-06-0109

Program as described in LRA Section B.1.19.

B.1.19

11 Enhance the Oil Analysis Program to periodically sample A.2.1.22 October 17, 2014 JAFP-06-0109

lubricating oil in the security generator, the fire pump

diesel, as well as the oil internal to underground oil filled cables. B.1.20 JAFP-07-0079

Enhance the Oil Analysis Program to include viscosity and

neutralization number determination of oil samples from

components that do not have regular oil changes.

Enhance the Oil Analysis Program to include particulate and

water content for oil replaced periodically.

A-4
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

_ LRA Section Schedule

12 Implement the One-Time Inspection Program as described in A.2.1.23 Will be JAFP-06-0109

LRA Section B.1.21. implemented

B.1.21 within the 10

years prior to

October 17, 2014

13 Enhance the Periodic Surveillance and Preventive A.2.1.24 October 17, 2014 JAFP-06-0109

Maintenance Program as necessary to assure that the effects

of aging will be managed in accordance with B.1.22

JAF-RPT-05-LRD02.

14 Enhance the Reactor Vessel Surveillance Program to include A.2.1.26 October 17, 2014 JAFP-06-0109

the data analysis, acceptance criteria, and corrective actions

described in LRA Section B.1.24. B.1.24

15 Implement the Selective Leaching Program in accordance with A.2.1.27 October 17, 2014 JAFP-06-0109

the program as described in LRA Section 8.1.25.

B.1.25

Audit Item 443 & 445

A-5
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Sectionl Implementation

LRA Section Schedule

16 Enhance the Structures Monitoring Program procedure to:

specify that manholes, duct banks, underground fuel oil

tank foundations, manway seals and gaskets, hatch

seals and gaskets, underwater concrete in the intake

structure, and crane rails and girders are included in

the program.

include guidance for performing structural

examinations of elastomers and rubber components to

identify cracking and change in material properties.

include guidance for performing periodic inspections to

confirm the absence of aging effects for lubrite

surfaces in the drywell radial beam seats and for lubrite

surfaces in the torus support saddles.

perform an engineering evaluation on a periodic basis

(at least once every five years) of groundwater

samples to assess aggressiveness (pH < 5.5, chloride

> 500 ppm and Sulfate > 1500) of groundwater to

concrete.

inspect any inaccessible concrete areas that may be

exposed by excavation for any reason, or any

inaccessible area where observed conditions in

accessible areas, which are exposed to the same

environment, show that significant concrete

degradation is occurring.

A.2.1.30

B.1.27.2

Audit Item 203 &287

Audit Item 201

Audit Item 201

October 17, 2014 JAFP-06-01 09

L .1. J

A-6
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation LRA Section Schedule

17 Implement the Thermal Aging and Neutron Irradiation A.2.1.31 October 17, 2014 JAFP-06-0109

Embrittlement of Cast Austenitic Stainless Steel (CASS)

Program as described in LRA Section B.1.28. B.1.28

18 Enhance the Water Chemistry Control - Auxiliary Systems A.2.1.32 October 17, 2014 JAFP-06-0109

Program to include guidance for sampling the control room and

relay room chilled water, decay heat removal cooling water, B.1.29.1

and the security generator jacket cooling water.

19 Enhance the Bolting Integrity Program to include guidance from A.2.1.35 October 17, 2014 JAFP-06-0109

EPRI NP-5769 and EPRI TR-104213.

Enhance the Bolting Integrity Program to clarify that actual yield B.1.30

strength is used in selecting materials for low susceptibility to

SCC and to clarify the prohibition on use of lubricants

containing MoS2 for bolting.

20 At least 2 years prior to entering the period of extended 4.3.3 October 17, 2014 JAFP-06-0167

operation, for the locations identified in NUREG/CR-6260 for

BWRs of the JAFNPP vintage, JAFNPP will implement one or Audit Item 317

more of the following:

(1) Refine the fatigue analyses or develop new analyses

(Class I RHR piping and Class 1 feedwater piping locations), if

necessary, to determine valid CUFs less than 1 when

accounting for the effects of reactor water environment. This

includes applying the appropriate Fen factors to valid CUFs

determined in accordance with one

of the following options.

A-7
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

LRA Section Schedule

1. For locations, including NUREG/CR-6260 locations,

with existing fatigue analysis valid for the period of

extended operation, use the existing CUF to determine

the environmentally adjusted CUF.

2. More limiting JAFNPP-specific locations with a valid

CUF may be added in addition to the NUREG/CR-6260

locations.

3. Representative CUF values from other plants,

adjusted to or enveloping the JAFNPP plant specific

external loads may be used if demonstrated applicable

to JAFNPP,

4. For locations, including NUREG/CR-6260 locations,

an analysis using the NRC-approved ASME code 2001

edition up to and including 2003 addendum, may be Audit Item 485 &487

performed to determine a valid CUF.

The determination of Fen will account for operating time with

normal water chemistry and operating time with hydrogen water

chemistry.

(2) Manage the effects of aging due to fatigue at the affected

locations by an inspection program that has been reviewed and

approved by the NRC (e.g., periodic non-destructive

examination of the affected locations at inspection intervals to

be determined by a method acceptable to the NRC).

(3) Repair or replace the affected locations before exceeding a

CUF of 1.0. J. .L I I

A-8
APPENDIX A: JAFNPP LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation LRA Section Schedule

Should JAFNPP select the option to manage environmentally

assisted fatigue during the period of extended operation, details

of the aging management program such as scope, qualification,

method, and frequency will be submitted to the NRC at least 2

years prior to the period of extended operation.

21 Enhance the BWR Vessel Internals Program to inspect fifteen A.2.1.7 and B.1.7 As stated in the JAFP-07-0048

(15) percent of the top guide locations using enhanced visual commitment

inspection techniques. EVT-1, within the first 18 years of the Audit Item 252

period of extended operation, with at least one-third of the

inspections to be completed within the first six (6) years and at

least two-thirds within the first 12 years of the period of

extended operations. Locations selected for examination will be

areas that have exceeded the neutron fluence threshold.

22 Enhance the BWR Vessel Internals Program to ensure the A.2.1.7 and B.1.7 October 17, 2014 JAFP-06-0167

effects of aging on the steam dryer are managed in accordance

with the guidelines of BWRVIP-1 39 as approved by the NRC Audit Item 245

and accepted by the BWRVIP Executive Committee.

23 Enhance the BWR Vessel Internals Program to perform A.2.1.7 and B.1.7, October 17, 2012 JAFP-07-0019

inspections of the core plate rim hold down bolts. 4.7.3.2

Appendix A.2.2.7 Core Plate is revised to add that JAFNPP will Audit Item 252

perform one of the following: A.2.2.7

1. Install core plate wedges prior to the period of extended Audit Item 483

operation; or, RAI 4.7.3.2-1

2. Complete a plant-specific analysis to determine acceptance

criteria for continued inspection of core plate rim hold down

A-9
11 APPENDIX A: JAFNPP L ICENSE RENEWAL COMMITMENTS

Commitment UFSAR Enhancement or Source

Supplement Section/ Implementation

LRA Section Schedule

bolting in accordance with BWRVIP-25 and submit the

inspection plan, along with the acceptance criteria and

justification for the inspection plan, to the NRC two years prior

to the period of extended operation for NRC review and

approval.

If Option 2 is selected, the analysis to determine acceptance

criteria will address the information requested in RAIs 3.1.2-2A

and 4.7.3.2-1.

24 Implement the Bolted Connections Program as described in A.2.1.36 October 17, 2014 JAFP-07-0019

LRA Section B.1.31.

B.1.31

Audit item 296

25 Implement the Oil-Filled Cable System aging management that B.1.11 October 17, 2014 JAFP-07-0048

will be controlled by the following programs:

B.1.20

External Surfaces Monitoring Program

Oil Analysis Program B.1.22

Periodic Surveillance and Preventive Maintenance Program

A-10
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 Nuclear

Operations, Inc. (ENO). This appendix also lists other correspondence on the staff's review of the

James A. FitzPatrick Nuclear Power Plant (JAFNPP) license renewal application (LRA) (under

Docket No. 50-333).

APPENDIX B: CHRONOLOGY I

Date Subject

June 26, 2006 Meeting slides of Entergy Nuclear presentation to NRC on plans for

submittal of license renewal application for JAFNPP (ADAMS

Accession No. ML062070267)

July 27, 2006 Summary of June 26, 2006 meeting between the U.S. NRC Staff and

Entergy Nuclear Operations, Inc (ENO) representatives to discuss

readiness of JAFNPP LRA (ADAMS Accession No. ML062090176)

July 31, 2006 In a letter (signed by Pete Dietrich) (ADAMS Accession

No. ML062160491), ENO submitted its application to renew the

operating license of the JAFNPP. In its submittal, CEG provided 'an

original signed hard copy of the application, with additional electronic

copies of the application on CDs. Cover Page through Chapter 4

(ADAMS Accession No. ML062160494), Appendix A (ADAMS

Accession No. ML062160553), Appendix B through Appendix D

(ADAMS Accession No. ML062160556), Appendix E (ADAMS

Accession No. ML062160557)

July 31, 2006 In a letter (signed by Pete Dietrich), ENO submitted a-list of LRA

Boundary Drawings used for the scoping phase of license renewal

(ADAMS Accession No. ML062140125)

August 2, 2006 NRC released the 51 referenced boundary drawings. The drawings

can be found within an ADAMS package (ADAMS Accession

No. ML062140129)

August 4, 2006 NRC Press Release-06-100: NRC Announces Availability of LRA For

JAFNPP (ADAMS Accession No. ML062160240)

August 7, 2006 In a letter (signed by P. T. Kuo), the NRC acknowledged receipt and

availability of the LRA for JAFNPP (ADAMS Accession

No. ML062190106)

B-1
APPENDIX B: CHRONOLOGY

Date Subject

August 11, 2006 In the Federal Register, a "Notice of Receipt and Availability of

Application for Renewal of James A. FitzPatrick Nuclear Power Plant"

is published, concerning the JAFNPP LRA

(ADAMS Accession No. ML071000081)

September 7, 2006 In a letter (signed by S. Hernandez), to Ms. Carol Ferlito of the

Oswego Public Library, the NRC verified the library's willingness to

maintain public documents related to the JAFNPP LRA (ADAMS

Accession No. ML062500247)

September 7, 2006 In a letter (signed by S. Hernandez), to Ms. Mary Bennett of the

Penfield Library, the NRC verified the library's willingness to maintain

public documents related to the JAFNPP LRA (ADAMS Accession

No. ML062500286)

September 14, 2006 In a letter (signed by F. Gillespie), to Mr. Peter Dietrich of ENO, the

NRC provided Notice of Acceptance for Docketing of the Application

and Notice of Opportunity for Hearing Regarding the LRA (ADAMS

Accession No. ML062570127)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable Barry E.

Snyder, Seneca Nation of Indians, the NRC requested comments

concerning the JAFNPP LRA environmental review. (ADAMS

Accession No. ML062480035)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable Roger Hill,

Tonawanda Band of Senecas, the NRC requested comments

concerning the JAFNPP LRA environmental review. (ADAMS

Accession No. ML062480044)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable James

Ransom, St. Regis Mohawk Tribe, the NRC requested comments

concerning the JAFNPP LRA environmental review. (ADAMS

Accession No. ML062480053)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable Irving Powless

Jr., Onondaga Indian Nation, the NRC requested comments

concerning the JAFNPP LRA environmental review. (ADAMS

Accession No. ML062480057)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable Ray Halbritter,

Oneida Indian Nation, the NRC requested comments concerning the

JAFNPP LRA environmental review. (ADAMS Accession

No. ML062480063)

B-2
APPENDIX B: CHRONOLOGY

Date Subject

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable William Jacobs,

Cayuga Nation, the NRC requested comments concerning the

JAFNPP LRA environmental review. (ADAMS Accession

No. ML062480069)

September 15, 2006 In a letter (signed by R. Franovich), to The Honorable Leo Henry,

Tuscarora Nation, the NRC requested comments concerning the

JAFNPP LRA environmental review. (ADAMS Accession

No. ML062480035)

September 15, 2006 In a letter (signed by Rani Franovich) to Ms. B. Castro, the NRC

notified the New York State Office of Parks, Recreation, and Historic

Preservation, that a site-specific Supplemental Environmental Impact

Statement (SEIS) to its "Generic Environmental Impact Statement for

License Renewal of Nuclear Plants". (GEIS), NUREG-1437, will be

prepared under the provisions of 10 CFR Part 51, the NRC rules that

implement the National Environmental Policy Act of 1969 (NEPA).

The letter also invited the office staff to the NEPA scoping meetings

for the JAFNPP LRA. (ADAMS Accession No. ML062480220)

September 15, 2006 In a letter (signed by Rani Franovich) to Mr. Don Klima, the NRC

notified the Advisory Council on Historic Preservation, that a

site-specific Supplemental Environmental Impact Statement (SEIS) to

its "Generic Environmental Impact Statement for License Renewal of

Nuclear Plants" (GELS), NUREG-1437, will be prepared under the

provisions of 10 CFR Part 51, the NRC rules that implement the

National Environmental Policy Act of 1969 (NEPA). The letter also

invited the office staff to the NEPA scoping meetings for the JAFNPP

LRA. (ADAMS Accession No. ML062480229)

September 19, 2006 In a letter (signed by R. Franovich) to Mr. Marvin Moriarty of the US

Fish and Wildlife Office, the NRC requested a list of protected species

within the evaluation area of the LRA review (ADAMS Accession

No. ML062630292)

September 20, 2006 NRC Press Release-06-114: NRC Announces Opportunity to Request

a Hearing on the LRA for JAFNPP (ADAMS Accession

No. ML062630056)

September 20, 2006 In the Federal Register, a "Notice of acceptance for docketing of the

application, notice of opportunity for hearing and notice of intent to

prepare an environmental impact statement and conduct scoping

process" is published, concerning the JAFNPP LRA (ADAMS

Accession No. ML071000085)

B-3
APPENDIX B: CHRONOLOGY

Date Subject

September 26, 2006 In a letter (signed by R. Franovich) to Mr. Peter Dietrich of ENO, the

NRC provided Notice of Intent to Prepare an Environmental Impact

Statement and Conduct Scoping Process under the provisions of

10 CFR Part 51, to implement the National Environmental Policy Act

of 1969 (NEPA) for License Renewal for JAFNPP (ADAMS Accession

No. ML062480235)

October 3, 2006 NRC Press Release-l-06-055: NRC to Discuss Process for Review of

LRA for JAFNPP, Seek Input on Environmental Review (ADAMS

Accession No. ML062760465)

October 12, 2006 NRC Slides from environmental scoping meeting held on October 12,

2006 (ADAMS Accession No. ML062960154)

October 23, 2006 NRC released the Audit and Review Plan for the JAFNPP LRA

(ADAMS Accession No. ML062780155)

October 30, 2006 NRC released a summary of the environmental scoping meetings

held on October 12, 2006 (ADAMS Accession No. ML062980148)

October 30, 2006 NRC released the transcript of the afternoon (1:30 pm) environmental

scoping meeting held on October 12, 2006 (ADAMS Accession

No. ML063030195)

October 30, 2006 NRC released the transcript of the evening (7:00 pm) environmental

scoping meeting held on October 12, 2006 (ADAMS Accession

No. ML063030209)

October 30, 2006 NRC released a summary of the public environmental scoping

meetings held on October 12, 2006 (ADAMS Accession

No. ML062980148)

November 7, 2006 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML062850382)

November 7, 2006 In a letter (signed by R. Franovich) to Mr. Kenneth P. Lynch of the NY

State Department of Environmental Conservation, the NRC requested

a list of protected species within the evaluation area of the LRA

review (ADAMS Accession No. ML062630292)

November 14, 2006 In a letter (signed by Joseph Heath, General Council) to the NRC, the

Onondaga Nation opposed renewal of the operating license of

JAFNPP (ADAMS Accession No. ML063240283)

November 14, 2006 In a letter (signed by Chris Hogan, PM) to the NRC, the NY State

Dept. Of Env. Conservation provided its comments on the JAFNPP

environmental review (ADAMS Accession No. ML063240331)

B-4
APPENDIX B: CHRONOLOGY

Date Subject

November 22, 2006 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML063200113)

November 27, 2006 In a letter (signed by S. Hernandez) to Mr. Michael Kansler of ENO,

the NRC scheduled its Environmental Site Audit (ADAMS Accession

No. ML063250406)

November 29, 2006 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML063200126)

November 30, 2006 In a letter (signed by Tara Seoane, Information Services) to the NRC,

the NY State Natural Heritage Program provided a list of rare plants

and animals within the JAFNPP environmental review site (ADAMS

Accession No. ML063470489)

December 4, 2006 NRC released the Aging Management Program (AMP) audit Q & A

database (ADAMS Accession No. ML063400415)

December 6, 2006 In a letter (signed by Pete Dietrich) (ADAMS Accession

No. ML063480585), ENO submitted amendment No. 1 to its

application to renew the operating license of the JAFNPP. The

amendment contained the License Renewal Commitments List

(ADAMS Accession No. ML063480596) as well as responses to RAIs

December 7, 2006 In a letter (signed by Anthony Wonderley, Historian) to the NRC, the

Oneida Indian. Nation explained the JAFNPP was outside of their

territory (ADAMS Accession No. ML063480314)

December 21, 2006 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 2

to its application to renew the operating license of the JAFNPP. The

amendment contained responses to RAIs (ADAMS Accession

No. ML063600160)

December 28, 2006 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 3

to its application to renew the operating license of the JAFNPP. The

amendment contained responses to scoping and screening RAIs

(ADAMS Accession No. ML070030392)

January 8, 2007 In a letter (signed by K. Howard) to Mr. Michael Kansler, the NRC

informed ENO of environmental PM and scheduling changes (ADAMS

Accession No. ML063550121)

January 12, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML070080014)

B-5
APPENDIX B: CHRONOLOGY

Date Subject

January 19, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML070120196)

January 24, 2007 In a letter (signed by Robert Snyder, Section Chief) to the NRC, the

NY Department of Health supplied previously requested

environmental information (ADAMS Accession No. ML063240283)

January 26, 2007 NRC released a summary of the environmental site audit conducted

the week of 12/4/06 (ADAMS Accession No. ML070220055)

January 29, 2007 In aletter (signed by Pete Dietrich), ENO submitted amendment No. 4

to its application to renew the operating license of the JAFNPP. The

amendment contained responses to RAIs (ADAMS Accession

No. ML0700370170)

February 1, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 5

to its application to renew the operating license of the JAFNPP. The

amendment contained responses to RAIs (ADAMS Accession

No. ML070440127)

February 7, 2007 NRC released the updated Aging Management Program (AMP) and

Aging Management Review (AMR) audit Q & A database (ADAMS

Accession No. ML070380389)

February 12, 2007 Note to File (signed by N. B. Le) - Docketing of email correspondence

related to JAFNPP LRA (ADAMS Accession No. ML070440181)

February 12, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 6

to its application to renew the operating license of the JAFNPP. The

amendment contained responses to RAIs (ADAMS Accession

No. ML070520263)

February 14, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 7

to its application to renew the operating.license of the JAFNPP. The

amendment contained responses to RAls (ADAMS Accession

No. ML-070530316)

February 20, 2007 Note to File (signed by Pete Dietrich) - Docketing of email

correspondence related to JAFNPP LRA (ADAMS Accession

No. ML070520059)

February 20, 2007 NRC received an email from ENO containing GE document

NE-B1 100732-01, Revision 1 "Plant Fitzpatrick RPV Surveillance

Materials Testing and Analysis of 120deg Capsule @ 13.4 EFPY"

(ADAMS Accession No. ML070520661)

B-6
APPENDIX B: CHRONOLOGY

Date Subject

February 23, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML070370023)

March 2, 2007 In a letter (signed by J. Davis) to Mr. Michael Kansler of ENO, the

NRC provided the Environmental Scoping Summary Report

associated with the review of JAFNPP LRA (ADAMS Accession

No. ML070440393)

March 7, 2007 In a letter (signed by R. Franovich), to Ed Alkiewicz, Senior

Environmental Scientist with NY Power Authority, the NRC provided

information concerning transmission line corridors related to the

JAFNPP LRA review (ADAMS Accession No. ML070400185)

March 12, 2007 NRC released a summary of a telephone conference held on

February 26, 2007 between ENO and NRC staff to discuss RAIs

(ADAMS Accession No. ML070600186)

March 14, 2007 NRC released a summary of a telephone conference held on

March 5, 2007 between ENO and NRC staff to discuss RAIs (ADAMS

Accession No. ML070670266)

March 15, 2007 NRC released a summary of the telephone conferences held on

January 31, 2007 and February 13, 2007 between ENO and NRC

staff to discuss RAIs (ADAMS Accession No. ML070670227)

April 2, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML070850605)

April 6, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 8

to its application to renew the operating license of the JAFNPP. The

amendment dealt with RAls related to section 4.3.1 of the LRA

(ADAMS Accession No. ML071070214)

April 6, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment No. 9

to its application to renew the operating license of the JAFNPP. The

amendment contained updated commitments, responses to RAls, and

an updated audit Q & A database (ADAMS Accession

No. ML071060390)

April 10, 2007 In a letter (signed by Pete Dietrich) to NY State Dept. Of

Environmental Conservation, ENO applied for an extended water

quality permit (ADAMS Accession No. ML071170388)

B-7
APPENDIX B: CHRONOLOGY

Date Subject

April 24, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment

No. 10 to its application to renew the operating license of the

JAFNPP. The amendment contained responses to RAIs (ADAMS

Accession No. ML071210240)

April 25, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML071100235)

May 4, 2007 Note to File (signed by N.B. Le) - Docketing of email correspondence

related to JAFNPP LRA (ADAMS Accession No. ML071270080)

May 4, 2007 In an email (from N.B. Le) to Mr. Rick Plasse fo ENO, the NRC

requested clarification on an RAI response (ADAMS Accession

No. ML071270377)

May 17, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment

No.11 to its application to renew the operating license of the JAFNPP.

(ADAMS Accession No. ML071430185)

May 21, 2007 In a letter (signed by Edward Alkiewicz, Environmental Studies

Manager) to the NRC, the NY Power Authority provided a response

regarding potential stream crossing erosion (ADAMS Accession

No. ML063240283)

May 21, 2007 In a letter (signed by R. Franovich) to Mr. Marvin Moriarty of the US

Fish and Wildlife Office, the NRC provided a biological assessment

for the LRA review (ADAMS Accession No. ML071160167)

May 21, 2007 NRC released a biological assessment for the JAFNPP LRA (ADAMS

Accession No. ML071160186)

May 24, 2007 NRC released a summary of a telephone conference held on

March 21, 2007 between ENO and NRC staff to discuss RAls

(ADAMS Accession No. ML070960030)

June 4, 2007 NRC released a notice of a significant public meeting on June 21,

2007 to discuss inspection results cover scoping and AMP portions of

LRA review. (ADAMS Accession No. ML071550279)

June 8, 2007 In a letter (signed by R. L. Franovich) to Mr. Michael Kansler of ENO,

the NRC informed Entergy of the availability of site-specific

supplement 31 to the Generic Environmental Impact Statement for

the JAFNPP LRA. (ADAMS Accession No. ML071240156)

June 8, 2007 In a letter (signed by R. L. Franovich) to Ms. Carol Ash of NY Parks,

Recreation & Historic Preservation, the NRC updated the status of its

environmental review. (ADAMS Accession No. ML071240271)

B-8
APPENDIX B: CHRONOLOGY

Date Subject

June 8, 2007 In a letter (signed by R. L. Franovich) to the US Environmental

Protection Agency, the NRC filed the site-specific supplement 31 to

the Generic Environmental Impact Statement for the JAFNPP LRA.

(ADAMS Accession No. ML071240405)

June 19, 2007 In a letter (signed by N. B. Le) to Mr. Michael Kansler of ENO, the

NRC informed Entergy of the availability of a report documenting the

results of the audit and LRA review. (ADAMS Accession

No. ML071580049)

June 20, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment

No.12 to its application to renew the operating license of the JAFNPP.

(ADAMS Accession No. ML071770168)

July 10, 2007 Note To File - Docketing of Document (Fire Protection Plan) recived

from the applicant (ADAMS Accession No. ML071970491)

July 25, 2007 In a letter (signed by N.B. Le) to Mr. Peter Dietrich of ENO, the NRC

provided Requests for Additional Information for the Review of

JAFNPP LRA (ADAMS Accession No. ML072010267)

July 31, 2007 In a letter (signed by P. T. Kuo) to Mr. Peter Dietrich of ENO, the NRC

provided Entergy with a Safety Evaluation Report (SER) with Open

Items. (ADAMS Accession No. ML071580299)

July 31, 2007 In a Memo (signed by Rajender Auluck) to Mr. Frank Gillespie the

Advisory Committee on Reactor Safeguards (ACRS), requested that

ACRS review the Safety Evaluation Report (SER) with Open Items for

the JAFNPP LRA. (ADAMS Accession No. ML071570249)

August 1, 2007 Meeting Briefing Package/ Handouts, slides, viewgraphs regarding

draft SEIS Public meeting on August 1, 2007 (ADAMS Accession

No. ML072260023)

August 1, 2007 Meeting Transcript for Public Meeting on August 1, 2007 Regarding

Draft SEIS for Fitzpatrick. (ADAMS Accession Nos. ML072260053,

ML072260420)

August 2, 2007 Inspection Report - IR 05000333-07-007 Scoping of Non-Safety

Systems and the Proposed Aging Management Procedures for the

James A. Fitzpatrick Nuclear Power Plant Application for Renewed

License. (ADAMS Accession No. ML072140637)

August 7, 2007 Federal Register Notice, Meeting Notice FRN - Plant License

Renewal ACRS Subcommittee meeting on September 5, 2007 to

review the James A. Fitzpatrick Nuclear Power Plant Application for

Renewed License. (ADAMS Accession No. ML072200097)

B-9
APPENDIX B: CHRONOLOGY

Date Subject

August 14, 2007 In a letter (signed by Pete Dietrich), ENO submitted Amendment

No. 13 to its application to renew the operating license of the

JAFNPP. (ADAMS Accession No. ML072330077)

August 20, 2007 Comment on NUREG-1437, Supplement 31, draft SEIS, from J

Costedio of Entergy Nuclear Northeast (ADAMS Accession

No. ML072530437)

September 5, 2007 Meeting Agenda, Meeting Briefing Package/Handouts, Slides and

Viewgraphs for ACRS Sub-Committee Meeting. (ADAMS Accession

No. ML072690529)

September 26, 2007 Note to File - Docketing of Slides presentation to ACRS License

Renewal subcommittee (ADAMS Accession No. ML072690528)

October 31, 2007 Technical Report, ENT-FLU-002-R-005, Revision 0, "James A.

Fitzpatrick, License Renewal Application - Amendment 14, Fluence

Calculation," Non-Propriety Version. (ADAMS Accession

No. ML073180496)

November 5, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment

No. 14 to its application to renew the operating license of the

JAFNPP. (ADAMS Accession No. ML073180494)

November 16, 2007 In a letter (signed by Pete Dietrich), ENO submitted amendment

No. 15 to its application to renew the operating license of the

JAFNPP. (ADAMS Accession No. ML073320168)

November 19, 2007 Note - Docketing of correspondence pertaining to applicant's

comments Regarding the Safety Evaluation Report With Open Items

Related to James A. Fitzpatrick, License Renewal Application.

(ADAMS Accession Nos. ML073250085, ML073300433,

and ML073300435)

January 18, 2008 NRC Letter (signed by R Franovich) to Michael Balduzzi of Entergy,

providing notice of availability of the final site specific Supplement #31

to the GElS (ADAMS Accession Nos. ML073380155, ML080170183)

January 24, 2008 Meeting Summary documenting information regarding telephone

conference call, dated January 08, 2008, with the applicant regarding

FitzPatrick 115 kV AC power supply power (ADAMS Accession

No. ML073380155)

January 24, 2008 NRC Letter (signed by PT Kuo) to P Dietrich, regarding Safety

Evaluation Report of FitzPatrick NPP January 24, 2008 (ADAMS

Accession No. ML080250372)

B-10
APPENDIX B: CHRONOLOGY

Date Subject

February 14, 2008 Memorandum to F Gillespie regarding ACRS review of FitzPatrick

NPP (ADAMS Accession No. ML080360149)

February 14, 2008 NRC Letter (signed by N Le) to P. Dietrich of FitzPatrick NPP,

transmitting the Audit Team's Evaluation of the Audit Questions &

Answers data base for the FitzPatrick LRA Audit (ADAMS Accession

No. ML080420252)

March 24, 2008 Note To File - Documenting slides presentation/ view graphs on

March 6, 2Q08, pertaining to the ACRS review of the FitzPatrick LRA

(ADAMS Accession Nos. ML080800034, ML080840048, and

ML080840082)

B-11

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

S. Arora Audit Team Member

H. Ashar Structural Engineering

R. Auluck Management Oversight

R. Franovich Management Oversight

W. Bateman Management Oversight

J. Canady Audit Team Member

T. Chan Management Oversight

K. Chang Management Oversight

G. Chevrouski Vessels & Internals Integrity

R. Dennig Management Oversight

M. Evans Management Oversight

T. Ford Reactor Systems

G. Galletti Scoping & Screening

F. Gillespie Management Oversight

Q. Gan General Engineer

K. Green Scoping & Screening

V. Goel Electrical Engineering

K. Gruss Management Oversight

H. Hamzehee Management Oversight

P. Hiland Management Oversight

C. Holden Management Oversight

C-1
APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

K. Howard Project Manager

R. Hsu GALL Audit and Review

E. Imbro Management Oversight

N. lqbal Fire Protection

A. Black Vessels & Internals Integrity

D. Hoang Civil & Structural

P. Kuo Management Oversight

N. Le License Renewal Project Manager

B. Lee Containment Ventilation

S. Lee Management Oversight

B. Lehman Engineer Intern

Y. Malave Quality & Vendor Inspection

K. Manoly Management Oversight

R. Mathew Audit Team Leader

G. Meyer Region I Inspections

J. Medoff Flaw Evaluations & Welding

M. Mitchell Management Oversight

M. Modes Region I Inspections

J. Muir Environmental Project Manager

D. Nguyen Electrical Engineering

P. Patel' Structural Engineering

W. Ruland Management Oversight

B. Rogers Scoping & Screening

J. Segala Management Oversight

J. Sharkey Management Oversight

D. Shum Balance of Plant

C-2
APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

A. Stubbs Balance of Plant

D. Thatcher Management Oversight

J. Tsao Flaw Evaluations & Welding

M. Tschiltz Management Oversight

H. Walker Containment Ventilation

S. Weerakkody Management Oversight

J. Wermiel Management Oversight

G. Wilson Management Oversight

J. Zimmerman Management Oversight

CONTRACTORS

Name Responsibility

Legin Group, Inc SER Support

Brookhaven National Laboratory GALL Audit

Pacific Northwest Laboratories Balance of Plant

C-3

APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report (SER) for review

of the license renewal application (LRA) for James A. FitzPatrick Nuclear Power Plant.

REFERENCES

Number References

1 JAFNPP License Renewal Application, dated August 1, 2006

2 NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," September 2005.

3 NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report,"

September 2005.

4 NEI 95-10, Revision 5, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54 - The License Renewal Rule," September 2005.

5 Letter from the NRC to Entergy, "Request for Additional Information for the Review

of the James A. FitzPatrick Nuclear Power Plant License Renewal Application,"

dated November 22, 2006 (ADAMS Accession No. ML063200113).

6 Letter from Entergy to the NRC, "Entergy Nuclear Operations Inc., James A.

FitzPatrick Nuclear Power Plant, Docket No. 50-333, License No. DPR-59, License

Renewal Application, Amendment 2," dated December 21, 2006 (ADAMS

Accession No. ML063600160).

Scoping and Screening Methodology Audit Trip Report Regarding the Entergy

Nuclear FitzPatrick, LLC and Entergy Nuclear Operations, Inc., License Renewal

Application for the James A. FitzPatrick Nuclear Power Plant, dated March 7, 2007

(ADAMS Accession No. ML070710235).

8 NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle

Cracking," November 1980.

9 NUREG-0313, Revision 2, "Technical Report on Material Selection and Processing

Guidelines for BWR Coolant Pressure Boundary Piping," 1988.

10 NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel

Piping," January 1988, Supplement 1, September 1992.

11 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for

Water-Cooled Power Reactors, Office of the Federal Register, National Archives

and Records Administration," 2000.

D-1
12 NUREG-1433, Revision 3, "Standard Technical Specifications General Electric

Plants, BWR/4," Volume 1, June 2004.

13 Regulatory Guide 1.137, "Fuel-Oil Systems for Standby Diesel Generators,"

Revision 1, October 1979.

14 ASTM Standard D 2276-00, "Standard Test Method for Particulate Contaminant in

Aviation Fuel by Line Sampling," 2000.

15 ASTM Standard D 2709-96, "Standard Test Method for Water and Sediment in

Middle Distillate Fuels by Centrifuge," 1996.

16 ASTM Standard D*4057-95, "Standard Practice for Manual Sampling of Petroleum

and Petroleum Products," 2000.

17 ASTM Standard D 1796-04, "Standard Test Method for Water and Sediment in Fuel

Oils by the Centrifuge Method," 2004.

18 ASTM Standard D 975-06, "Standard Specification for Fuel Oils," 2006.

19 ASTM Standard D 6217, "Standard Test Method for Particulate Contamination in

Middle Distillate Fuels by Laboratory Filtration," 2003.

20 IEEE Std. P1205-2000, "IEEE Guide for Assessing, Monitoring and Mitigating Aging

Effects on Class 1E Equipment Used in Nuclear Power Generating Stations."

21 NUREG/CR-5643, "Insights Gained From Aging Research," NRC: March 1992.

22 SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power

Plants Electrical Cable and Terminations," prepared by Sandia National

Laboratories for the U.S. Department of Energy, September 1996.

23 NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Austenitic Stainless Steels," U.S. Nuclear Regulatory Commission:

April 1999.

24 NUREG/CR-6260, "Application of NUREG/CR 5999 Interim Fatigue Curves to

Selected Nuclear Power Plant Components," U.S. Nuclear Regulatory Commission:

March 1995.

25 NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Carbon and Low-Alloy Steels," U.S. Nuclear Regulatory Commission:

March 1998.

26 NRC Generic Letter 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning," U.S.

Nuclear Regulatory Commission: May 2, 1989.

27 NRC IE Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants," U.S.

Nuclear Regulatory Commission: July 9, 1987.

28 "Cable and Terminations," prepared by Sandia National Laboratories for the U.S.

E l_ Department of Energy: September 1996.

D-2
29 NRC Information Notice 97-46, "Unisolable Crack in High-Pressure Injection

Piping," U.S. Nuclear Regulatory Commission: July 9, 1997.

30 Regulatory Guide 1.147, "Inservice Inspection Code Case Acceptability, ASME

Section XI, Division 1," Revision 14.

31 Regulatory Guide 1.65, "Materials and Inspections for Reactor Vessel Closure

Studs," October 1973.

32 ASME Boiler and Pressure Vessel Code, 1989 Edition, Section XI.

33 ASME Boiler and Pressure Vessel Code, 1998 Edition with 2000 Addenda,

Section XI.

341 NEI 03-08 "Guideline for the Management of Materials Issues," May 2003.

35 GSI 190, "Fatigue Evaluation of Metal Components for 60-year Life

NUREG/CR-6583 (ANL-97/18), Effects of LWR Coolant Environments on Fatigue

Design Curves of Carbon and Low-Alloy Steels," March 1998.

36 NUREG-0661, Mark 1 Long Term Program Technical Report MPR-751, "Mark 1

Containment Program Augmented Class 2/3 Fatigue Evaluation Method and

Results for Typical Torus Attached and SRV Piping Systems," November 1982.

37 NRC Letter, C. I. Grimes to C. Terry, Safety Evaluation for Referencing of BWR

Vessel and Internals Project, "BWR Core Plate Inspection and Flaw Evaluation

Guidelines (BWRVIP-25) Report for Compliance with the License Renewal Rule

(10 CFR Part 54) and Appendix B, BWR Core Plate Demonstration of Compliance

with the Technical Information Requirements of the License Renewal Rule

(10 CFR 54.21)," December 7, 2000.

38 NRC Letter, C. I. Grimes (NRC) to C. Terry, (BWRVIP Chairman), Acceptance for

Referencing of EPRI Proprietary Report TR-113596, "BWR Vessel and Internals

Project, BWR Reactor Vessel Inspection and Flaw Evaluation Guidelines

(BWRVIP-74) and Appendix A, Demonstration of Compliance with the Technical

Information Requirements of the License Renewal Rule (10 CFR 54.21),"

October 18, 2001.

39 NRC Letter, M. K. Gamberoni (NRC) to J. Knubel (PASNY), "Relief Request No. 17

- Request for Relief from the Requirements of 10 CFR 50.55a(g)(6)(ii)(A)(2) for

Augmented Inspection of the Circumferential Welds in. the Reactor Vessel of the

James A. Fitzpatrick Nuclear Power Plant (TAC No. MA6215)," February 22, 2000.

40 NRC Letter, G. C. Lainas (NRC) to C. Terry (BWRVIP), "Final Safety Evaluation of

the BWR Vessel and Internals Project BWRVIP-05 Report (TAC No. M93925),"

July 28, 1998.

41 BWRVIP-74-A (EPRI Report 1008872), "BWRVIP-74-A: BWR Vessel and Internals

Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines

for License Renewal," June 2003.

D-3
42 BWRVIP-135 (EPRI Report 1011019), "BWR Vessel and Internals Project,

Integrated Surveillance Program (ISP) Data Source Book and Plant Evaluations,"

2004.

43 JAF Updated Final Safety Analysis Report, Revision 12, May 2005.

44 NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of

10 CFR Part 50, Appendix J," March 1996.

45 ASME Boiler and Pressure Vessel Code, Section XI, Subsections IWA, IWC, IWD,

IWE, and IWF.

46 ASME Boiler and Pressure Vessel Code, Section XI, Subsection NF.

47 10 CFR Part 100, "Reactor Site Criteria."

48 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear

Power Plants."

49 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities."

50 10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and

Related Regulatory Functions."

51 NUREG-1437, Supplement 31, "Generic Environmental Impact Statement for

License Renewal of Nuclear Power Plants Regarding James A. FitzPatrick Nuclear

power Plant Draft Report for Comment," June 8, 2007.

The following references were reviewed on site

52 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 3.1, "Buried Piping and Tanks Inspection,"

Revision 4.

53 JAF-RPT-05-LRD05, "JAFNPP License Renewal Project Operating Experience

Review Results," Revision 0, May 4, 2006.

54 Condition Report CR-JAF-1993-502, June 22, 1993.

55 NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle

Cracking," November 1980.

56 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.1, "BWR CRD Return Line Nozzle,"

Revision 4.

57 JPN-83-64, "CRD Return Line Modifications (NUREG-0619)," July 7, 1983.

58 NRC SER on JPN-83-64, "NRC Safety Evaluation of the CRD Return Line

Modifications," August 25, 1983.

D-4
59 JAFP-00-0239, "Letter to NRC: Proposed Alternative for the Contingency Repair of

the CRD Cap to RPV Nozzle per GL 88-01 B Relief Request (RR-26),"

October 15, 2000.

60 NRC SER on JAFP-00-0239, "NRC Safety Evaluation by the Office of NRR:

Alternative to ASME Code, Section XI, Repair Requirements for Weld Overlay

Repair of RPV Nozzle to the CRD Return Line Cap Weld," October 26, 2000.

61 JAF-ISI-0002, "JAFNPP Third Ten-Year ISI Program, " Revision 4.

62 Generic Letter 88-01, "NRC Position on Intergranular Stress Corrosion Cracking

(IGSCC) in BWR Austenitic Stainless Steel Piping."

CR-JAF-2000-05044, "Examination Revealed a Crack in the CRD Nozzle Cap to

63 Nozzle Weld," October 15, 2000.

64 JAF-RPT-05-LRD05, "JAFNPP License Renewal Project Operating Experience

Review Results," Section 4.1.1, "BWR CRD Return Line Nozzle," Revision 2.

65 CR-JAF-2006-00581, "Class 1 ISI Inspection of BWR CRD Return Line Nozzle."

66 GE-NE-523-A71-0594, "Alternate BWR Feedwater Nozzle Inspection

Requirements," Revision 1, August 1999.

67 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.2, "BWR Feedwater Nozzle," Revision 4.

68 NYF-78-003/FI-78-36 "Safety Evaluation - FW Nozzle Modification,"

August 17, 1978.

69 JPN-99-003, "Commitment Change - Feedwater Nozzle Leakage Monitoring

System," February18, 1999.

70 NYPA-62Q-302,-"Updated Feedwater Nozzle Fracture Mechanics Analysis for

FitzPatrick Updated Crack Growth Analysis," Revision 1.

71 NRC Letter, "Feedwater Nozzle Cracking in BWRs," July 21, 1986.

72 SIR-02-045 (W-NYPA-78Q-401), "Updated Fatigue Analysis for James A.

Fitzpatrick Nuclear Power Plant Reactor Pressure Vessel Components,"

September 2002.

73 JAF-RPT-05-LRD05, "JAFNPP License Renewal Project Operating Experience

Review Results," Section 4.1.2, "BWR Feedwater Nozzle," Revision 2.

74 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.3, "BWR Penetrations," Revision 4.

75 JAF-RPT-NBS-01848, "Reactor Vessel Integrity," Revision 3.

76 JAF-RPT-MULT-01 120, "IGSCC Inspection Program," Revision 6, March 28, 2005.

D-5
77 JAF-RPT-05-LRD05, "JAFNPP License Renewal Project Operating Experience

Review Results," Section 4.1.3, "BWR Penetrations," Revision 2.

78 BWRVIP-27, BWR Vessel and Internals Project, "BWR Standby Liquid Control

System/Core Plate P Inspection and Flaw Evaluation Guidelines, (EPRI TR-107286,

April 1997)," Final License Renewal Safety Evaluation Report by the Office of

Nuclear Reactor Regulation for BWRVIP-27 for Compliance with the License

Renewal Rule (10 CFR Part 54), December 20,1999.

79 BWRVIP-49, BWR Vessel and Internals Project, "Instrument Penetration Inspection

and Flaw Evaluation Guidelines, (EPRI TR-108695, March1998)," Final License

Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for

BWRYIP-49 for Compliance with the License Renewal Rule (10 CFR Part 54),

September 1, 1999.

80 NUREG-0313, "Technical Report on Material Selection and Processing Guidelines

for BWR Coolant Pressure Boundary Piping," Revision 2, 1988.

81 NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel

Piping," January 1988, Supplement 1, September 1992.

82 BWRVIP-75-A (EPRI TR-1 13932) Technical Basis for Revisions to Generic Letter

88-01 Inspection Schedules, February 2000 SER, September 2000.

83 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.4, "BWR Stress Corrosion Cracking,"

Revision 4.

84 JAF-UT-89-1, "Manual Ultrasonic Examination Austenitic and Dissimilar Metal

Piping Welds," Revision 0.

85 JAF-RPT-05-LRD05, "JAFNPP License Renewal Project Operating Experience

Review Results," Section 4.1:4, "BWR Stress Corrosion Cracking," Revision 2.

86 JAF-RPT-05-LRD02, Section 4.5, "Aging Management Program Evaluation

Results," Revision 0.

87 JAF-RPT-05-LRD05, "Operating Experience Review Report," Revision 0.

88 BWRVIP-48-A, "BWR Vessel and Internals Project Vessel ID Attachment Weld

Inspection and Flaw Evaluation Guidelines," June 2004.

89 JAF-RPT-NBS-01848, "Reactor Vessel Integrity and In-Vessel Visual Inspection

Program," Revision 10.

90 JAF-RPT-NBS-04394, "Assessment of Vessel Internals Health," Revision 2.

91 AP-05.14, "ASME Section Xl Repair/Replacement Program," Revision 7.

92 JAFP-05-0151 "Request for Approval of Relief Request No. RR-39,"

October 7, 2005.

D-6
93 JAFP-06-0059, "Response to Request for Additional lnformation(RAI),"

April 3, 2006.

94 WPO-LO-2005-069 LOCR# WPO-LO-2005-069, October 12, 2005.

95 LO-WPOLO-2005-00056-CA-00001, Condition Report

LO-WPOLO-2005-00056-CA-00001.

96 BWRVIP-59, "Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in

RPV Internals, (EPRI TR-1 08710)," BWRVIP and Electric Power Research Institute,

Palo Alto, CA, March 24, 2000.

97 BWRVIP-60, BWR Vessel and Internals Project, "Evaluation of Crack Growth in

A -BWR LowAlloy Steel RPV Internals, (EPRI TR-1 08709, April 14, 2000)," Final

Safety Evaluation Report by the Office ofNuclear Reactor Regulation for

BWRVIP-60, July 8,1999.

98 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Revision 0, "Operating Experience Review Report," Section 4.1.6, "BWR Vessel

Internals Program."

99 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.6, "BWR Vessel Internals," Revision 4.

100 JAFNPP Procedure VT-FPK-204V7, "Procedure For Invessel Visual Inspection

(IVVl) of BWR 4 RPV Internals at FitzPatrick," Revision 2, September 27, 2004.

101 Request for Approval of Relief Request No. RR 39, "James A. FitzPatrick Nuclear

Power Plant, Docket No. 50-533, License No. DPR-59, Implementation of BWRVIP

Guidelines in lieu of ASME Section Xl Code Requirements on Reactor Vessel

Internals and Components Inspection," October 7, 2005.

102 Letter from Richard J. Laufer (NRC) to Mr.Michael Kansler, President, Entergy

Nuclear Operations, Inc., "James A. FitzPatrick Nuclear Power Plant - Relief

Request No. RR-39, Implementation of BWRVIP Guidelines in Lieu of ASME

Section XI Code Requirements on Reactor Vessel Internals and Components

Inspection (TAC No. MC8587)," August 30, 2006.

103 Condition Report No. "CR-JAF-2006-04531," October 27, 2006.

104 Condition Report No. "CR-JAF-2006-04238," October 19, 2006.

105 Condition Report No. "CR-JAF-2006-04287," October 20, 2006.

106 JAFNPP Engineering Report (Deviation Disposition) No. JAF-05-34054, "Jet Pump

Inaccessible Welds and Deferral of Beam UT Inspections," Revision 0, March 16,

2006.

107 Interface Control Document No. JAF-ICD-0300014, Revision 0, "JAF - IWI

Program Technical Justification, Alternative Technique for Inspection of Vessel

Internals Core Plate Rim Hold-Down Bolts (BWRVIP-25)," July 3, 2003.

D-7
108 Letter No. 97-870 from Carl Terry (BWRVIP) to the U.S. Nuclear Regulatory

Commission Document Control Desk, "BWRVIP Utility Commitments to the

BWRVIP," October 30,1997.

109 Letter No. 97-461 from Carl Terry (BWRVIP) to the U.S. Nuclear Regulatory

Commission Document Control Desk, "BWRVIP Utility Commitments

to the BWRVIP," May 30, 1997.

110 JAF-RPT-05-LRD02 A "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.7, "Containment Leak Rate Program,"

Revision 4.

111 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report," Section 4.1.7, "Containment Leak Rate

Program," Revision 0.

112 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for

Water-Cooled Power Reactors," Office of the Federal Register, National Archives

and Records Administration, 2000.

113 JAF-RPT-PC-02342, "Primary Containment Leakage Rate Testing Program Plan,"

Revision 7, April 14, 2005.

114 ENN-DC-334, "Primary Containment Leakage Rate Testing" (Appendix J),

Revision 0, July 26, 2004.

115 ENN-EP-S-001, "IWE General Visual Containment Inspection," Revision 0,

March 8, 2004.

116 EN-DC-147, "JAFNPP Containment Inservice Program Plan," Revision 0,

February 7, 2006.

117 NUREG-1433, "Standard Technical Specifications General Electric Plants, BWR/4

Vol. 1," Revision 3, June 2004.

118 Regulatory Guide 1.137, "Fuel-Oil Systems for Standby Diesel Generators,"

Revision 1, October 1979.

119 ASTM Standard D 2276-00, "Standard Test Method for Particulate Contaminant in

Aviation Fuel by Line Sampling," 2000.

120 ASTM Standard D 2709-96, "Standard Test Method for Water-and Sediment in

Middle Distillate Fuels by Centrifuge," 1996.

121 ASTM Standard D 4057-95, "Standard Practice for Manual Sampling of Petroleum

and Petroleum Products," 2000.

122 ASTM Standard D 1796-04, "Standard Test Method for Water and Sediment in Fuel

Oils by the Centrifuge Method," 2004.

123 ASTM Standard D 975-06, "Standard Specification for Fuel Oils," 2006.

D-8
124 Entergy Nuclear Operations Inc. James A. FitzPatrick Nuclear Power Plant,

Technical Specifications, Volume 3, Section 3.8.3.3, Section 5.5.10.

125 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 4.8, "Diesel Fuel Monitoring," Revision 4,

July 11, 2006.

126 SP-01.07, JAFNPP Surveillance Procedure, "Diesel Fuel Oil Sampling and

Analysis," Revision 7, May 26, 2005.

127 AM-02.36, JAFNPP Analytical Method, "Water and Sediment Analysis of Fuel Oil,"

Revision 2, August 14,1998.

128 ASTM Standard D 6217, "Standard Test Method for Particulate Contamination in

Middle Distillate Fuels by Laboratory Filtration," 2003.

129 Condition Report CR-JAF-2004-02631, June 22, 2004.

130 Condition Report CR-JAF-2002-01207, March 28, 2002.

131 Condition Report CR-JAF-2000-02022, May 24, 2000.

132 Condition Report CR-JAF-2000-05845, November 17, 2000.

133 JAF-RPT-05-LRD02, "Environmental Qualification of Electric Components,"

Section 4.9, Revision 2.

134 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.9, "Environmental Qualification of

Electric Components Containment Inservice Inspection," Revision 0.

135 ENN-DC-164, "Environmental Qualification (EQ) Program," Entergy Northeast

Nuclear Management Manual, Revision 2, November 1, 2005.

-136 EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

137 IEEE Std. P1205-2000, "IEEE Guide for Assessing, Monitoring and Mitigating Aging

Effects on Class 1 E Equipment Used in Nuclear Power Generating Stations."

138 NUREG/CR-5643, "Insights Gained From Aging Research," U. S. Nuclear

Regulatory Commission, March 1992.

139 SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power

Plants Electrical Cable and Terminations," prepared by Sandia National

Laboratories for the U.S. Department of Energy, September 1996.

140 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Report,"

Section 4.10, "External Surfaces Monitoring," Revision 4.

141 JAF-RPT-05-LRD05, "Operating Experience Review Report," Section 4.1.10,

Revision 0.

D-9
142 EN-LI-102, "Corrective Action Process," Revision 4.

143 EN-DC-178, "System Walkdowns," Revision 0.

144 EN-MA-101, "Conduct of Maintenance," Revision 1.

145 EN-MS-S-011-Multi, "Conduct of System Engineering," Revision 0.

146 ENN-TK-ESPG-033, "Engineer Qualification Card: Conduct Walkdowns of

Assigned Systems," Revision 0.

147 CR-JAF-2003-01156, "Small leak in HPCI Steam Supply Isolation Valve found

during system walkdown," October 9, 2003.

148 CR-JAF-2003-04807, "Corrosion found under metal roof decking of Auxiliary Boiler

Building during structural monitoring walkdown," March 11, 2003.

149 INPO Good Practice TS-413, "Use of System Engineers," INPO 85-033,

May 18, 1988.

150 EPRI Technical Report 1007933, "Aging Assessment Field Guide,"

December 2003.

151 EPRI Technical Report 1009743, "Aging Identification and Assessment Checklist,"

August 27, 2004.

152 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD02,

Section 4.11, "Fatigue Monitoring."

153 JAFNPP Reactor Analyst Procedure RAP 7.4.10, "Component Cyclic or Transient

Limit Program," Revision 2, January 2, 2004.

154 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.11, "Fatigue Monitoring

Program," Revision 0.

155 NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Austenitic Stainless Steels," U.S. Nuclear Regulatory Commission,

April 1999.

156 NUREG/CR-6260, "Application of NUREG/CR 5999 Interim Fatigue Curves to

Selected Nuclear Power Plant Components," U.S. Nuclear Regulatory Commission,

March 1995.

157 NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Carbon and Low-Alloy Steels," U.S. Nuclear Regulatory Commission,

March 1998.

158 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Report,"

Section 4.12.1, "Fire Protection," Revision 2.

D-10
159 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.12, "Fire Protection Program,"

Revision 0.

160 MST-076.1 1, "Fire Barrier Penetration Functional Integrity Surveillance Test,"

Revision 17.

161 ST-76A, "Fire Protection System Monthly Checks," Revision 18.

162 ST-76D, "High Pressure Water and Cardox Fire Protection System Operational

Test," Revision 27.

163 ST-76J23, "West Diesel Fire Pump 76P-1 Performance Test," Revisioni16.

164 MP-076.01, "Diesel-Fire Pump Engine 76P 1(ENG)," Maintenance Procedure,

Revision 1.

165 MP-076.16, "Fire Door Maintenance," Revision 12.

166 TRM, "JAFNPP Technical Requirements Manual," Revision 12.

167 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Report,"

Section 4.12.2, "Fire Water System," Revision 2.

168 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.13, "Fire Water System

Program," Revision 0.

169 MST-076.1 1, "Fire Barrier Penetration Functional Integrity Surveillance Test,"

Revision 11.

170 ST-76E, "Quarterly Fire Hose Station Inspections," Revision 15.

171 ST-76F, "Fire Hose Station Gasket Inspection and Hose Rerack Test," Revision 5.

172 ST-76FA, "High Radiation Area Fire Hose Inspection and Rerack," Revision 2.

173 ST-76K, "Fire Header Integrity and Nozzle Inspection," Revision 7.

174 ST-76U, "Fire System Flow Test," Revision 10.

175 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Results,"

Section 4.13, Revision 2.

176 ENN-DC-1 47, "Flow Accelerated Corrosion Program Basis Document," Revision 2.

177 ENN-CS-S-008, "Pipe Wall Thinning Structural Evaluation," Revision 0.

178 JAF-RPT-05-LRD05, "Operating Experience Review Report," Section 4.1.14,

Revision 0.

179 ENN-DC-315, "Flow Accelerated Corrosion Program," Revision 0.

D-11
180 ENN-EP-S-005, "Flow Accelerated Corrosion Component Scanning and Gridding

Standard," Revision 0.

181 ENN-NDE-9.05, "Ultrasonic Thickness Examination," Revision 0.

182 NRC Generic Letter 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning," U.S.

Nuclear Regulatory Commission, May 2, 1989.

183

184 NRC IE Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants," U.S.

Nuclear Regulatory Commission, July 9, 1987.

185 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 3.2, "Heat Exchanger Monitoring," Revision 4,

July 11, 2006.

186 Condition Report CR-JAF-2005-04859, November 28, 2005.

187 ENN-EP-S-001, "ENN Engineering Standard-IWE General Visual Containment

Inspection," Revision 0, March 8, 2004.

188 JAF-RPT-PC- 04088, "JAF First Containment Inservice Inspection Interval Program

Plan," Revision 5, May 5, 2005.

189 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.14.2, "Containment Inservice Inspection,"

Revision 4.

190 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.16, "Inservice Inspection -

Containment Inservice Inspection Program," Revision 0.

191 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD02,

Section 4.14.1, "Inservice Inspection," Revision 2.

192 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, Section 4.1.15, "Inservice Inspection

Program," Revision 0.

193 Entergy Nuclear North (ENN) Engineering Report, JAF-ISI-0002, Revision 4,

JAFNPP Third Ten Year In-service Interval Inspection Program, April 20, 2005.

194 Condition Report No. CR-JAF-2004-04472, October 8, 2004.

195 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 3.3, "Metal-Enclosed Bus Inspection,"

Revision 2.

196 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 3.4, "Non-EQ Instrumentation Circuits Test

Review," Revision 2.

D-12
197 EPRI TR-109619, "Guideline for the Management of Adverse Localized Equipment

Environments," Electric Power Research Institute, Palo Alto, CA, June 1999.

198 Cable and Terminations, Prepared by Sandia National Laboratories for the US

Department of Energy, September 1996.

199 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 3.5, "Non-EQ Insulated Cables and

Connections," Revision 2.

200 EN-DC-310, "Predictive Maintenance Program," Revision 0.

201 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

____ Program Evaluation Report, Section 4.16 "Oil Analysis," Revision 2.

202 Aging Management Review Evaluation Report (AMPER) JAF-RPT-05-LRD05,

Operating Experience Review Report, "Oil Analysis Program," Section 4.1.17,

Revision 0.

203 MP-1 01.41, "Sampling of Lubricants for the Plant Lube Oil Analysis Program,"

Revision 16.

204 MP-093.08, "DG Lube Oil Sampling," Revision 6.

205 ENN-DC-324, "Preventive Maintenance Process," Revision 0.

206 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 3.6, "One-Time Inspection," Revision 4,

July 11, 2006.

207 NRC Information Notice 97-46, "Unisolable Crack in High-Pressure Injection

Piping," U.S. Nuclear Regulatory Commission, July 9,1997.

208 EPRI Report 1000701, "Interim Thermal Fatigue Management Guideline

(MRP-24)," January 2001.

209 Condition Report CR-JAF-2000-05123, October 17, 2000.

210 Condition Report CR-JAF-2000-00461, February 9, 2000.

211 Condition Report CR-JAF-2000-02793, June 29, 2000.

212 Condition Report CR-JAF-2000-00919, March 11, 2000.

213 Condition Report CR-JAF-2000-01196, April 3, 2000.

214 Condition Report CR-JAF-2000-00698, February 25, 2000.

215 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.17, "Periodic Surveillance and Preventive

Maintenance," Revision 4.

216 DESO-12 JAFNPP Design Engineering Standing Order, "Maintenance Rule

Structural Assessment and Monitoring Program," Revision 3, May 26, 2004.

D-13
217 MP-088.02 JAFNPP Maintenance Procedure, "Reactor Building Crane Inspection

88CR2," Revision 16, January 5, 2006.

218 ST-18C JAFNPP Operations Surveillance Test Procedure, "Control Room

Ventilation Air Handling Unit Performance Test," Revision 5, June 22, 2005.

219 Condition Report CR-JAF-2000-03580, August 9, 2000.

220 JAFNPP-ISI-0003, "Third Inservice Inspection Interval, Ten Year Inspection Plan,"

Revision 5.

221 ASTM A 540, "Standard Specification for Alloy Steel Bolting Materials for Special

Applications," May 2004.

222 AP-19.04, "ISI System Pressure Test Procedure," Revision 4.

223 MP-004.01, "Disassembly of Reactor Vessel for Refueling (ISI)," Revision 30.

224 MP-004.02, "Reassembly of Reactor Vessel After Refueling (ISI)," Revision 33.

225 AP-05.14, "ASME Section XI Repair/Replacement Program," Revision 6.

226 GE Purchase Specification 21A1 100, Revision 0, "Standard Requirements for

Reactor Pressure Vessel."

227 Regulatory Guide 1.147, "Inservice Inspection Code Case Acceptability, ASME

Section XI, Division 1," Revision 14.

228 Regulatory Guide 1.65, "Materials and Inspections for Reactor Vessel Closure

Studs,". October 1973.

229 ASME Boiler and Pressure Vessel Code, 1989 Edition, Section XI.

230 ASME Boiler and Pressure Vessel Code, 1998 Edition with 2000 Addenda,

Section XI.

231 JPN-04-01 0, "Request to Use the 1998 Edition, 2000 Addenda of the American

Society of Mechanical Engineers (ASME) Section Xl Code Requirements for the

Examination of Reactor Vessel Closure Studs." JAFNPP Request No. R-33,

"Proposed Use of Subsequent ASME Code Edition and Addenda in Accordance

withl0 CFR 50.55a(g)(4)(iv)."

232 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Results," Revision 2.

233 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Report,

Section 4.20, "Service Water Integrity," Revision 4.

234 DB-46, "Design Basis Document for the Normal Service Water, Emergency Service

Water, and RHR Service Water," Revision 16.

235 JAF-RPT-MULTI-01267, "Raw Water Systems Program Plan," Revision 3.

236 AP-19.12, "Service Water Inspection Program," Revision 4.

D-14
237 AP-1 9.14, "Eddie Current Testing of Heat Exchanger Tubes," Revision 7.

238 ST-2Y, "RHR Heat Exchanger Performance Test," Revision 7.

239 OP-42A, "Service Water Chemical Cleaning System," Revision 2.

240 ST-8Q, "Testing of the Emergency Service Water System (IST)," Revision 34.

241 JPN-90-15, JAFNPP Correspondence to NRC: "Response to NRC Generic Letter

89-13 Service Water System Problems Affecting Safety Related Equipment,"

February 13, 1990.

242 JPN-91-15, JAFNPP Correspondence to NRC: "Updated Response to NRC

Generic Letter 89-13 Service Water System Problems Affecting Safety-Related

Equipment," April 18, 1991.

243 JPN-93-15, JAFNPP Correspondence to NRC: "Updated Response to NRC

Generic Letter 89-13 Service Water System Problems Affecting Safety-Related

Equipment," March 16, 1993.

244 WO #JF-030374800, "Perform Eddy Current Inspection of 'D' Diesel Cooler,"

Revision 0, March 6, 2003.

245 JAF-RPT-BYM-02306, "Maintenance Rule Basis Document for System 052

Structures," Revision 2, April 10, 2001.

246 JAF-RPT-BYM-02636, "Structures (System 052) for 10 CFR 50.65, Maintenance

Rule," Revision 4, April 8, 2004.

247 JAF-RPT-05-LRD02 A JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 4.21.2, "Masonry Wall," Revision 2.

248 JAF Updated Final Safety Analysis Report, Revision 12, May 2005.

249 SP-01.11, "Unmonitored Paths Sampling and Analysis," Revision 15.

250 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 4.21.1, "Structures Monitoring," Revision 2.

251 JAF-RPT-05-LRD02, JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 3.8, "Thermal Aging and Neutron Irradiation

Embrittlement of CASS Program," Revision 4.

252 JAF-RPT-05-LRD02 A JAFNPP License Renewal Project Aging Management

Program Evaluation Report, Section 3.8, "Thermal Aging and Neutron Irradiation

Embrittlement of Cast Austenitic Stainless Steel," Revision 2.

253 JAF-RPT-05-LRD02, "JAFNPP License Renewal Project Aging Management

Program Evaluation Report," Section 4.22.1, "Water Chemistry Control-Auxiliary

Systems," Revision 2. .

254 RT-01.06, "EHC, Stator Cooler Sampling and Analysis," Revision 12.

D-15
255 RT-01.08, "Hot Water Boiler and Glycol Hot Water Sampling and Analysis,"

Revision 6.

256 EPRI TR 1004004, "Generator Cooling System Operating Guidelines,"

December 2001.

257 EN-CY-1 01, "Chemistry Activities," Revision 0.

258 TIL 1098-3R3, "Inspection of Generators with Water Cooled Stator Windings,"

August 20, 2001.

259 BWRVIP-1 30, "BWR Water Chemistry Guidelines 2004."

260 NEI 03-08, "Guideline for the Management of Materials Issues," May 2003.

261 PC-01.01, "Hydrogen Water Chemistry and Zinc Injection Program," Revision 6.

262 RT-01.02, "Feedwater and Condensate Sampling and Analysis," Revision 9.

263 RT-01.05, "Makeup Demineralized System Sampling and Analysis," Revision 12.

264 SP-01.02, "Reactor Water Sampling and Analysis," Revision 19.

265 CR-JAF-2000-00335, "Average Feedwater Iron for January will more than likely be

above the Industry Median Value of 2.1 ppb," January 29, 2000.

266 CR-JAF-2004-04898, "Reactor Water Sulfate Exceeded Action Level 1 on Startup,"

October 24, 2004.

267 JAF-RPT-05-LRD05, JAFNPP License Renewal Operating Experience Review

Results, Section 4.1.25, "BWR Water Chemistry B BWR," Revision 2.

268 JAF-RPT-05-LRD02, "Aging Management Program Evaluation Report,"

Section 4.22.3, "Water Chemistry Control-Closed Cooling Water," Revision 4.

269 EPRI TR 1007820, "Closed Cooling Water Chemistry Guideline, Revision 1 to EPRI

TR 107396," Revision 1.

270 RT-01.23, "Diesel Fire Pump, Emergency Diesel Generator Coolant Corrosion

Inhibitor Sampling and Analysis," Revision 6.

271 RT-01.25, "Reactor Building Closed Loop Cooling Sampling and Analysis,"

Revision 11.

272 EPRI, "Closed Cooling Water Chemistry Guideline, Gap Analysis."

273 CR-JAF-2000-00968, "TBCLC dissolved oxygen increasing at a rate that requires

the deoxygenation skid more frequently," March 15, 2000.

274 CR-JAF-2000-05973, "RBCLC increasing conductivity, sulfate, and nitrate at steady

and increasing rate," November 30, 2000.

275 CR-JAF-2000-00804, "TBCLC dissolved oxygen level determined to be greater than

action level of 3000 ppb," February 28, 2002.

D-16
276 CR-JAF-2000-00673, "RBCLC has experienced some abnormal chemistry

problems for an extended period," February 11, 2003.

277 JAF-CALC-04-00434, "TBCLC Corrosion Rates," February 25, 2004.

278 Aging Management Program Evaluation Report (AMRER) No. JAF-RPT-05-LRD02,

Section 4.23, "Bolting Integrity," Revision 2.

279 EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants,"

Volumes 1 and 2, April 1988.

280 EPRI TR-104213, "Bolted Joint Maintenance & Application Guide, Electric,"

:December 1995.

281 AMM31, Aging Management Review of the Reactor Pressure Vessel.

282 AMM32, Aging Management Review of the Reactor Vessel Internals.

283 AMM33, Aging Management Review of the Reactor Coolant System Pressure

Boundary.

284 AMM02, Aging Management Review of Residual Heat Removal System.

285 AMM03, Aging Management Review of Core Spray System.

286 AMM04, Aging Management Review of Automatic Depressurization System.

287 AMM05, Aging Management Review of High Pressure Coolant Injection System.

288 AMM06, Aging Management Review of Reactor Core Isolation Cooling.

289 AMM07, Aging Management Review of Standby Gas Treatment System.

290 AMM08, Aging Management Review of the Primary Containment Atmosphere

Control and Dilution System.

291 AMM01, Aging Management Review of Standby Liquid Control System.

292 AMM1 1, Aging Management Review of Service Water Systems.

293 AMM12, Aging Management Review of Emergency Diesel Generator System.

294 AMM13, Aging Management Review of Fuel Oil System.

295 AMM14, Aging Management Review of Fire Protection-Water System.

296 AMM15, Aging Management Review of Fire Protection-CO 2.

297 AMM16, Aging Management Review of Heating, Ventilation and Air Conditioning

Systems.

298 AMM19, Aging Management Review of Fuel Pool Cooling and Cleanup System.

299 AMM20, Aging Management Review of the Instrument Air System.

D-17
300 AMM21, Aging Management Review of the Reactor Building Closed Cooling Water

System.

301 AMM22, Aging Management Review of the Plant Drains Systems.

302 AMM23, Aging Management Review of the Security Generator.

303 LRD02, Aging Management Program Evaluation Results.

304 LRD05, Operating Experience Review Results.

305 LRD06, Aging Management Review Summary.

306 CR-JAF-2005-009631, "Spent Fuel Pool 'Boral' coupons not removed at the

scheduled interval as committed to in Technical Specifications Amendments,"

February 16, 2005.

307 AMM18, Aging Management Review of Condensate Storage System.

308 AMM30, Aging Management Review of Nonsafety-Related Systems and

Components Affecting Safety-Related Systems.

309 LRA-FB-49A-0, "Flow Diagram Fire Protection Water Piping System 76,"

Revision 40.

310 AMM17, Aging Management Review of Primary Containment Penetrations.

311 AMC01, Aging Management Review of the Reactor Building and Primary

Containment.

312 AMC02, Aging Management Review of Water Control Structures.

313 AMC03, Aging Management Review of the Turbine Building Complex and Yard

Structures.

314 AMC04, Aging Management Review of Bulk Commodities.

315 LRD04, TLAA-Mechanical Fatigue.

316 AME01, Electrical Screening and Aging Management Reviews.

317 LRPG-05, Electrical System Scoping, Screening and Aging Management Reviews.

318 JAF-LRPG-08, TLAA and Exemption Evaluations.

319 JAF-RPT-05-LRD03, TLAA and Exemption Evaluation Results.

320 Combustion Engineering, Inc. Nuclear Components Department Analytical Report

No. CENC-1 159, "Analytical Report for PASNY Reactor Vessel for FitzPatrick

Nuclear Station," August 1971.

321 Entergy Nuclear North License Renewal Document No. JAF-RPT 05-LRD-04,

Revision 1, "TLAA - Mechanical Fatigue," July 10, 2004.

D-18
322 SIR-02-045, "Updated Fatigue Analysis for James A. Fitzpatrick Nuclear Power

Plant Reactor Pressure Vessel Components," September 2002.

323 JAF-SE-03-002, "Updated Reactor Pressure Vessel Fatigue Analysis 10 CFR 50.59

Evaluation," Revision 0.

324 JAFP-00-0239 Letter to NRC dated 15 October 2000, "Repair of the Control Rod

Drive Cap to Reactor Pressure Vessel Nozzle."

325 JAF Modification JD-00-010, "CRD Cap Overlay."

326 JAF-RPT-NBS-04394, "Assessment of Vessel Internals Health," June 2005.

327 JAF-RPT-NBS-01 848, "Reactor Vessel Integrity and In-Vessel Visual Inspection

Program," Revision 10.

328 GE Report MDE-21-0185, "JAFNPP Feedwater Nozzle Rapid Cycling Fatigue

Analysis," January 1985.

329 JENG-05-0130, "Thermal Cycle Monitoring Report," January 1, 2005 through

June 30, 2005.

330 RAP-7.4; 10, "Component Cyclic or Transient Limit Program," Revision 2.

331 SI File No. W-NYPA-78Q-301, "Updated Cycle Counts and 60 Year Projections,"

Revision 1.

332 JAFP-05-0131, JAFNPP letter, T.A. Sullivan to NRC dated August 26, 2005,

LER-05-003, "Plant Shutdown Due to Through-Wall Crack in Torus."

333 DRN-03-00794, "Minor Calculation Change Form, Calculation No. SIR-02-045,"

Revision 1.

334 GSI 190, "Fatigue Evaluation of Metal Components for 60-year Life

NUREG/CR-6583 (ANL-97/18), Effects of LWR Coolant Environments on Fatigue

Design Curves of Carbon and Low-Alloy Steels," March 1998.

335 BWRVIP letter (EPRI letter 2005-271), Potential Error in Existing Fatigue Reactor

Water Environmental Effects Analyses, July 1, 2005.

336 MPR 291-9401-202, "Tie Rod Assembly Stress Evaluation, Core Shroud Repair,"

Revision 1.

337 MFN 06-133, Letter dated May 12, 2006, Jason S. Post of GE Energy to NRC

Part 21 60-Day Interim Report Notification: Core Shroud Repair Tie Rod Upper

Support Cracking.

338 NEDC-32068, "Reactor Pressure Vessel Power Uprate Stress Report

Reconciliation for the Fitzpatrick Power Plant," March 1992.

339 EAS-149-1286, "Reactor Pressure Vessel Fatigue Evaluation for the James A.

Fitzpatrick Nuclear Power Plant," January 1987.

D-19
340 JAF-CALC-06-00085, "Weld Overlay Design for Recirculation Outlet Nozzle

N-1 B-SE," Revision 0, October 6, 2006.

341 ER-JAF-06-22617, "Weld Overlay for Recirculation Outlet N-1 B-SE Nozzle to

Safe-End."

342 JAF-RPT-LRD02, "Aging Management Program Evaluation Report," Section 4.9,

"Environment Qualification of Electrical Equipment Components."

343 JAF-RPT-LRD03, TLAA and Exemption Evaluation Results, Section 2.4,

"Environmental Qualifications of Electrical Equipment," Revision 1.

344 NUREG-0661, Mark 1 Long Term Program Technical Report MPR-751, "Mark 1

Containment Program Augmented Class 2/3 Fatigue Evaluation Method and

Results for Typical Torus Attached and SRV Piping Systems," November 1982.

345 Technical Report (TR) 5321-1, "Mark I Containment Program Plant-Unique Analysis

Report of the Torus Suppression Chamber for JAFNPP," Revision 1, September 25,

1984.

346 Technical Report (TR) 5321-2, "Mark I Containment Program Plant-Unique Analysis

Report of the Torus Attached Piping for JAFNPP," Revision 1, November 1984.

347 JAFNPP Engineering Report JAF-RPT-NBS-01 848, "Reactor Vessel Integrity and

In-Vessel Visual Inspection Program," Revision 10, June 2005.

348 JAF-ICD-03-00014, JAF IVVI Program Technical Justification, "Alternate Technique

for Inspection of Vessel Internals Core Plate Rim Hold Down Bolts (BWRVIP-25),"

Revision 0, July 2003.

349 General Electric Report GE-NE-B13-02049-00-01, "JAF Top Guide and Core Plate

Structural Margins in the Presence of Cracking, Final Report," Revision 0,

March 2000.

350 NRC Letter, C. I. Grimes to C. Terry, Safety Evaluation for Referencing of BWR

Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation

Guidelines (BWRVIP-25) Report for Compliance with the License Renewal Rule

(10 CFR Part 54) and Appendix B, BWR Core Plate Demonstration of Compliance

with the Technical Information Requirements of the License Renewal Rule

(10 CFR 54.21), December 7, 2000.

351 Technical Specifications LCOs and SRs, James A. Fitzpatrick Nuclear Power Plant,

Amendment 282.

352 JAFNPP Document JAF-ICD-RPV-03455, Fluence and ART for Beltline Axial Welds

as a Function of EFPY, 1 December 1999 NYPA letter JPN-94-041, W. A. Josiger

to USNRC Document Control Desk, James A. Fitzpatrick Nuclear Power Plant,

Docket No. 50-333, Generic Letter 92-01, Revision 1, "Reactor Vessel Structural

Integrity," August 10, 1994.

353 GE-NE-B1100732-01, Revision 1, February, 1998, "Plant Fitzpatrick RPV

Surveillance Materials Testing and Analysis of 120E Capsule at 13.4 EFPY."

D-20
354 RVID2, NRC's Reactor Vessel Integrity Database, Version 2.

355 NRC Letter, C. I. Grimes (NRC) to C. Terry, (BWRVIP Chairman), Acceptance for

Referencing of EPRI Proprietary Report TR-1 13596, "BWR Vessel and Internals

Project, BWR Reactor Vessel Inspection and Flaw Evaluation Guidelines

(BWRVIP-74) and Appendix A, Demonstration of Compliance with the Technical

Information Requirements of the License Renewal Rule (10 CFR 54.21),"

October.18, 2001.

356 NRC Letter, M. K. Gamberoni (NRC) to J. Knubel (PASNY), "Relief Request No. 17

- Request for Relief from the Requirements of 10 CFR 50.55a(g)(6)(ii)(A)(2) for

Augmented Inspection of the Circumferential Welds in the Reactor Vessel of the

James A. Fitzpatrick Nuclear Power Plant (TAC No. MA6215)," February 22, 2000.

357 NRC Letter, G. C. Lainas (NRC) to C. Terry (BWRVIP), "Final Safety Evaluation of

the BWR Vessel and Internals Project BWRVIP-05 Report (TAC No. M93925),"

July 28, 1998.

358 BWRVIP-74-A (EPRI Report 1008872), "BWRVIP-74-A: BWR Vessel and Internals

Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines

for License Renewal," June 2003.

359 BWRVIP-135 (EPRI Report 1011019), "BWR Vessel and Internals Project,

Integrated Surveillance Program (ISP) Data Source Book and Plant Evaluations,"

2004.

360 MPR-1560, "James A. Fitzpatrick Nuclear Power Plant Core Shroud Repair B

Design Report," Volume 1 of 3, Revision 0.

D-21

NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-2004) (Assigned by NRC, Add Vol.. Supp., Rev.,

NRCMD 3.7 and Addendum Numbers, if any.)

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse) NUREG-1905

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report Related to the License Renewal of James A. FitzPatrick Nuclear MONTH YEAR

Power Plant

Aprl 2008

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Tommy Le

7. PERIOD COVERED I(Inclusive Dates)

08/31/06-03/06/08

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; f contractor,

provide name and mailing address.)

Division of License Renewal

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

. Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission,

and mailing address.)

Same as above

10 SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the Nuclear Regulatory Commission's (NRC's) review of James A. FitzPatrick

* Nuclear Power Plant (JAFNPP) license renewal application (LRA). The NRC's Office of Nuclear Reactor Regulation has

reviewed the JAFNPP LRA for compliance with the requirements of Title 10 of the Code of Federal Regulations, Part 54 (10

CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," and prepared this report to

document its findings.

On August 1, 2006, the Nuclear Energy FitzPatrick, LLC, and Nuclear Energy Operations, Inc., submitted application for

renewal of JAFNPP, Operating License No. DPR-59, for a period of up to 20 years beyond the current license expiration date of

October 17, 2014. JAFNPP is of a Mark 1, General Electric 4, boiling water reactor design with a licensed power output for

2536 megawatt thermal (a gross electrical output of 881 megawatt electric.) JAFNPP is located approximately 7 miles

northeast of Oswego, New York.

The NRC James A. Fitzpatrick license renewal project manager is Tommy Le. Mr. Le may be reached at 301-415-1458.

SWritten correspondence should be addressed to the Division of License Renewal, U.S. Nuclear Regulatory Commission,

Washington, DC 20555-0001.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT

10 CFR Part 54, license renewal, James A. FitzPatrick, scoping and screening, aging management, unlimited

time-limited aging analysis, safety evaluation report 14. SECURITY CLASSIFICATION

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC ORM 351.200) PINTE ON ECYLED APE

NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
Fednm Rmcyclig Progrmm

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS