NUREG-1828

Safety Evaluation Report

Related to the License Renewal of

the Arkansas Nuclear One, Unit 2

Docket No. 50-368

Entergy Operations, Inc.

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001 -L
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NUREG-1828

Safety Evaluation Report

Related to the License Renewal of

the Arkansas Nuclear One, Unit 2

Docket No. 50-368

Entergy Operations, Inc.

Manuscript Completed: May 2005

Date Published: June 2005

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
ABSTRACT

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

One, Unit 2 (ANO-2), license renewal application (LRA) by the U.S. Nuclear Regulatory

Commission staff (staff). By letter dated October 14, 2003, Entergy Operations, Inc. (Entergy

or the applicant), submitted the LRA for ANO-2 in accordance with Title 10 of the Code of

Federal Regulations Part 54 (10 CFR Part 54 or the Rule). Entergy is requesting renewal of the

operating licenses for ANO-2, (Facility Operating License No. NPF-6) for a period of 20 years

beyond the current expiration dates (midnight, July 17, 2018).

The ANO site is located in southwestern Pope County, Arkansas, on a peninsula formed by

Lake Dardanelle. The NRC issued ANO-2 construction permit on December 6,1972. The

operating license were issued by the NRC on September 1, 1978. ANO-2 consists of a

Combustion Engineering pressurized water reactor unit licensed to generate 3026 megawattsthermal (MWt), or approximately 1023 megawatts-electric (MWe).

This SER presents the staff's review of information submitted to the NRC in the application.

The staff's conclusion of its review of the ANO-2 LRA can be found in Section 6 of this SER.

The NRC ANO-2 license renewal project manager is Mr. Gregory F. Suber. Mr. Suber may be

reached at 301-415-1124. Written correspondence should be addressed to the License

Renewal and Environmental Impacts Program, U.S. Nuclear Regulatory Commission,

Washington, DC 20555-001.

iii
TABLE-OF CONTENTS

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

TABLE OF CONTENTS ............. '...-.. v

ABBREVIATIONS .. xi

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

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

1.2 License Renewal Background 1-2

1.2.1 Safety Review 1-3

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

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

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

1.5 Summary of Open Items .. 1-9

1.6 Summary of Confirmatory Items .. 1-10

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

2. STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW .- 2-1 .......................... O'.................... !....................

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

2.1.2.1 Scoping Methodology .................. - .-. 2-2

2.1.2.2 Screening Methodology ........................... 2-6

2.1.3 Staff Evaluation ...................... 2-9

2.1.3.1 Scoping Methodology .2-9

2.1.3.2 Screening Methodology ............................ '.2-19

2.1.4 Conclusion ....... 2-22

2.2 Plant-Level Scoping Results .. . 2-23

2.2.1 Summary of Technical Information in the Application . . 2-23

2.2.2 Staff Evaluation .. .......... ;.. 2-23

2.2.3 Conclusion ........................... 2-25

2.3 System Scoping and Screening Results-Mechanical Systems . . 2-26

2.3.1 Reactor Coolant System .2-30

2.3.1.1 Reactor Vessel and Control Element Drive Mechanism Pressure

Boundary ..... 2-31

2.3.1.2 Reactor Vessel Internals .. 2-33

2.3.1.3 Class 1 Piping, Valves, and Reactor Coolant Pumps .. 2-34

2.3.1.4 Pressurizer .............-. ''. 2-36

2.3.1.5 Steam Generators ........... I ........... 2-38

2.3.2 Engineered Safety Features.Systems . . .2-41

2.3.2.1 Emergency Cogre ng 2-41

2.3.2.2' Containmnen't Spray System ... 2-43

2.3.2.3 Containment Cooling ................... 2-44

2.3.2.4 Containment Penetrations .'.......................... 2-47

2.3.2.5 Hydrogen Control ...................... 2-48
2.3.3 Auxiliary Systems ........................................

2.3.3.1 Spent Fuel Storage ...............................

2.3.3.2 Water Suppression Fire Protection ...................

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

2.3.3.4 Alternate ac Diesel Generator .......................

2.3.3.5 Chemical and Volume Control .......................

2.3.3.6 Halon Fire Protection and Reactor Coolant Pump Motor Oil

Leakage Collection ................................

2.3.3.7 Fuel Oil ........................................

2.3.3.8 Service Water ...................................

2.3.3.9 Auxiliary Building Ventilation ........................

2.3.3.10 Control Room Ventilation .........................

2.3.3.11 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2) ..

2.3.3.12 Other Miscellaneous Systems ......................

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

2.3.4.1 Main Steam .....................................

2.3.4.2 Main Feedwater ..................................

2.3.4.3 Emergency Feedwater .............................

,oping and Screening Results-Structures ..........................

2.4.1 Staff Evaluation Methodology ...............................

2.4.2 Containment and Containment Internals ......................

2-50

2-50

2-53

2-54

2-56

2-58

2-60

2-61

2-62

2-64

2-67

2-69

2-79

2-84

2-84

2-86

2-89

2-93

2-97

2-97

2.4 Sc

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

2.4.2.2 Staff Evaluation ........ ......................... 2-100

2.4.2.3 Conclusion ..................................... 2-102

2.4.3 Auxiliary Buildings, Turbine Building, and Yard Structures ........ 2-102

2.4.3.1 Summary of Technical Information in the Application .... 2-102

2.4.3.2 Staff Evaluation ................................. 2-105

2.4.3.3 Conclusion ..................................... 2-110

2.4.4 Intake Structure and Emergency Cooling Pond . .2-110

2.4.4.1 Summary of Technical Information in the Application .... 2-110

2.4.4.2 Staff Evaluation .2-112

2.4.4.3 Conclusion .2-114

2.4.5 Bulk Commodities ................. ..................... 2-114

2.4.5.1 Summary of Technical Information in the Application .... 2-114

2.4.5.2 Staff Evaluation ................................. 2-116

2.4.5.3 Conclusion ..................................... 2-120

2.5 Scoping and Screening Results-Electrical and Instrumentation and Controls

Systems.

2.5.1 Summary of Technical Information in the Application .

2.5.2 Staff Evaluation.

2.5.3 Conclusion.

2.6 Conclusion.

3. AGING MANAGEMENT REVIEW RESULTS .

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

3.0.1 Format of the Licence Renewal Application (LRA).

3.0.1.1 Overview of Table 1 .

3.0.1.2 Overview of Table 2 .

3.0.2 Staff's Review Process.

2-121

2-121

2-121

2-125

2-125

.. 3-1

.. 3-1

.. 3-2

.. 3-3

.. 3-3

.. 3-4

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

3.0.2.2 Review of AMR Results .3-6

3.0.2.3 NRC-Approved Positions .3-7

3.0.2.4 UFSAR Supplement .................... , . - .3-7

3.0.2.5 Documentation and Documents Reviewed . 3-7

3.0.3 Aging Management Programs .. 3-8

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

3.0.3.2 AMPs that are Consistent with the GALL Report with Exceptions

and/or Enhancements . 3-19

3.0.3.3 AMPs that are Plant-Specific . 3-43

3.0.4 Quality Assurance Program, Attributes Integral to Aging Management

Programs .. 3-89

3.0.4.1 Summary of Technical Information in Application . 3-89

3.0.4.2 Staff Evaluation . 3-90

3.0.4.3 Conclusion ............ 3-91

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

.......................................................... 3-93

3.1.1 Summary of Technical Information in the Application .. 3-93

3.1.2 Staff Evaluation .. 3-93

3.1.2.1 AMR Results,,That Are Consistent with the GALL Report . . 3-99

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

Which Further Evaluation Is Recommended .. 3-101

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

the GALL Report .. 3-111

3.1.3 Conclusion ............................... 3-142

3.2 Engineered Safety Features Systems , ..................... 3-143

3.2.1 Summary of Technical Information in the Application .. 3-143

3.2.2 Staff Evaluation .. 3-143

3.2.2.1 AMR Results That Are Consistent with the GALL Report . 3-146

3.2.2.2 AMR ResultsThat Are Consistent with the GALL Report, for

Which Further Evaluation is Recommended .. 3-148

3.2.2.3 AMR Results That Are NOT Consistent with the GALL Report

................ ............ 3-152

3.2.3 Conclusion .... .. . 3-170

3.3 Auxiliary Systems .................... .. ;....,3-171

3.3.1 Summary of Technical Information in the Application .. 3-171

3.3.2 Staff Evaluation ............... 3-171

3.3.2.1 AMR Results That Are Consistent with the GALL Report . 3-176

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

Which Further Evaluation Is Recommended .. 3-180

3.3.2.3 AMR Results That Are Not Consistent with the GALL Report

................................................ 3-187

3.3.3 Conclusion.. ................ , .. 3-238

3.4 Steam and Power Conversion Systems .. 3-239

3.4.1 Summary of Technical Information in the Application .. 3-239

3.4.2 Staff Evaluation .................. 3-239

3.4.2.1 .AMR Results.That Are Consistent with the GALL Report . 3-242

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

Which Further Evaluation Is Recommended .. 3-244

ivii
3.4.2.3 AMR Results That Are Not Consistent with the GALL Report

............................................... 3-248

3.4.3 Conclusion ............................................ 3-262

3.5 Structures and Component Supports ........... .. .................. 3-263

3.5.1 Summary of Technical Information in the Application .... ........ 3-263

3.5.2 Staff Evaluation ........................................ 3-263

3.5.2.1 AMR Results That Are Consistent with the GALL Report . 3-268

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

Which Further Evaluation Is Recommended ..... ....... 3-271

3.5.2.3 AMR Results That Are Not Consistent with the GALL Report

.. ............................................ 3-286

3.5.3 Conclusion ........... ................................. 3-298

3.6 Electrical and Instrumentation and Controls ......... .. ............... 3-299

3.6.1 Summary of Technical Information in the Application .... ........ 3-299

3.6.2 Staff Evaluation ........................................ 3-300

3.6.2.1 AMR Results That Are Consistent with the GALL Report . 3-303

3.6.2.2 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which Further Evaluation Is Recommended

.............................................. .3-309

3.6.2.3 AMR Results That Are Not Consistent with the GALL Report or

Not Addressed in the GALL Report ................... 3-310

3.6.3 Conclusion ............................................ 3-315

3.7 Conclusion for Aging Management ................................. 3-316

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

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

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

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

4.1.3 Conclusions .... ............... ......................... 4-3

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

4.2.1 Charpy Upper-Shelf Energy ................................. 4-5

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

4.2.1.2 Staff Evaluation ................................... 4-6

4.2.2 Pressurized Thermal Shock ............. .. .................. 4-7

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

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

4.2.3 Pressure-Temperature Limits ............ .. .................. 4-9

4.2.3.1 Summary of Technical Information in the Application ..... 4-10

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

4.2.4 FSAR Supplement ......................... 4-11

4.2.5 Conclusions ............................................ 4-11

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

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

4.3.1.1 Fatigue of ASME Class 1 Components ..... ........... 4-13

4.3.1.2 Fatigue of ASME Non-Class 1 Components .... ........ 4-14

4.3.1.3 Response to Industry Experience ...... .............. 4-15

4.3.2 Staff Evaluation ......................................... 4-18

4.3.2.1 Fatigue of ASME Class 1 Components ..... ........... 4-18

4.3.2.2 Fatigue of ASME Non-Class 1 Components ............ 4-18

viii
4.3.2.3 Response to Industry Experience .. ................... 4-20

4.3.3 Conclusion ............................................. 4-22

4.4 Environmental Qualification of Electrical Equipment .......... ........... 4-23

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

4.4.2 Staff Evaluatio .. :: 4-25

4.4.3 Conclusions ........... .... ..... 4-25

4.5 Concrete Containment Tendon Prestress ...... ........................ 4-26

4.5.1 Summary of Technical Information in the Application .... ......... 4-26

4.5.2 Staff Evaluation .............. ;; . . 4-26

4.5.3 Conclusions ........... ... 4-30

4.6 Containment Liner Plate and Penetration Fatigue Analyses .......... .... r 4-31

4.6.1 Summary of Technical Information in the Application ..... ........ 4-31

4.6.2 Staff Evaluation ............... 4-31

4.6.3 Conclusions ..... ......... 4-32

4.7 Other Plant-Specific Time-Limited Aging Analyses ........... ........... 4-33

4.7.1 Reactor Coolant System Piping Leak Before Break Analysis .... ... 4-33

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

4.7.1.2 Staff Evaluation ......... ......................... 4-34

4.7.1.3 FSAR Supplement ................................ 4-35

4.7.1.4 Conclusions ..................................... 4-36

4.7.2 Reactor Coolant Pump Code Case N-481 .4-36

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

4.7.2.2 Staff Evaluation .4-37

4.7.2.3 FSAR Supplement .4-38

4.7.2.4 Conclusions .4-38

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

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

4.7.3.2 Staff Evaluation .................................. 4-39

4.7.3.3 FSAR Supplement ............................... 4-39

4.7.3.4 Conclusions ..................................... 4-40

4.7.4 Steam Generator Tubes-Flow-Induced Vibration ..... .......... 4-40

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

4.7.4.2 Staff Evaluation .................................. 4-41

4.7.4.3 FSAR Supplement ................................ 4-41

4.7.4.4 Conclusions .................................... 4-41

4.7.5 Alloy 600 Nozzle Repairs ............... ................... 4-41

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

4.7.5.2 Staff Evaluation .................................. 4-42

4.7.5.3 FSAR Supplement ................................ 4-43

4.7.5.4 Conclusions ..................................... 4-44

4.7.6 High-Energy Line Break Analyses ......... .. ................ 4-44

4.7.6.1 Summary of Technical Information in the Application ..... 4-44

4.7.6.2 Staff Evaluation .................................. 4-44

4.7.6.3 FSAR Supplement ................................ 4-45

4.7.6.4 Conclusions ..................................... 4-45

4.8 Conclusions for Time-Limited Aging Analyses ............. ............ 4-46

fix
-

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

6. CONCLUSIONS............................ .......................................................... 6-1

APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL ........................................ A-1

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

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

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

APPENDIX E: REQUEST FOR ADDITIONAL INFORMATION ....................................... E-1

x
ABBREVIATIONS

AAC alternate alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

AERM aging effect requiring management

AFW auxiliary feedwater

AMP aging management program

AMR aging management review

ANO Arkansas Nuclear One

ANO-1 Arkansas Nuclear One, Unit 1

ANO-2 Arkansas Nuclear One, Unit 2

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

AWWA American Water Workers Association

B&PV Boiler and Pressure Vessel

BAC boric acid corrosion

BL Bulletin

BTP Branch Technical Position

BWR boiling-water reactor

CASS cast austenitic stainless steel

CCW component cooling water

CE Combustion Engineering

CEA control element assembly

CEDM control element drive mecanism

CEOG Combustion Engineering Owners Group

CFR Code of Federal Regulations

Cl confirmatory item

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CR condition report

CRD control rod drive

CS containment spray

CSB core support barrel

CVF cumulative usage factor

CVUSE charpy upper-shelf energy

CVCS chemical and volume control system

DBA Design-Basis Accident

DBD design basis document

DC direct current

xi
A

ECCS emergency core cooling system

ECP emergency cooling pond

EDG emergency diesel generator

EFPY effective full-power year

EFW emergency feedwater

EOL end of life

EPRI Electric Power Research Institute

EQ environmental qualification

ESF engineering safety feature

FAC Flow-accelerated corrosion

FAP fuel assembly plate

FIV flow-induced vibration

FMP fatigue monitoring program

FP Fire Protection

FSAR Final Safety Analysis Report

FW Feedwater

GALL Generic Aging Lessons Learned

GDC general design criterion

GEIS Generic Environmental Impact Statement

GL generic letter

GSI generic safety issue

HAZ heat-affected zone

HELB high-energy line break

HPSI high pressure safety injection

HVAC heating, ventilation, and air conditioning

HX heat exchanger

l&C instrumentation and controls

IASCC irradiation-assisted stress corrosion cracking

ICI in-core instrumentation

IGA intergranular attack

ISG interim staff guidance

IGSCC inter-granular stress corrosion cracking

IN information notice

IPA integrated plant assessment

ISG interim staff guidance

ISI inservice inspection

kV kilo-volt

KW kilo-watt

LBB leak before break

LOCA loss of coolant accident

LOSP loss of offsite power

LPSI low pressure safety injection

LR license renewal

xii
LRA license renewal application

LTOP low-temperature overpressure protection

LWR light water reactor

MCL main coolant line

MeV mega-electron volt

MIC microbiologically influenced corrosion

MNSA mechanical nozzle seal assembilies

MRP Material Reliability Program

MRV minimum required values

MSIS main steam isolation signal

MWe megawatts-electric

MWt megawatts-thermal

NDE non-destructive testing

NEI Nuclear Energy Institute

NESC National Electric Safety Code

NFPA National Fire Protection Association

NPS nominal pipe size

NRC U. S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

NSSS nuclear steam supply system

NUREG NRC technical report designation (Nuclear Regulatory Commission)

ODSCC outside-diameter stress corrosion cracking

P&ID piping and instrumentation diagram

pH potential hydrogen

ppm parts-per-million

PSPM periodic surveillance and preventive maintenance

P-T pressure-temperature

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

RAI request for additional information

RBHV reactor building heating and ventilation

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RFO refueling outage

RG regulatory guide

RHR residual heat removal system

RI-ISI risk-informed inservice inspection

RTD resistance temperature detector

RTPTS reference temperature (pressurized thermal shock)

RV reactor vessel

RVH reactor vessel head

xiii
RVI reactor vessel internals

RVID reactor vessel integrity database

RWT refueling water tank

RPV reactor pressure vessel

RTNDT nil-ductility reference temeprature

SAR safety analysis report

SBO station blackout

SCC stress corrosion cracking

SER safety evaluation report

SFP spent fuel pool

SG steam generator

SIAS safety injection actuation signal

SRP standard review plan

SS stainless steel

SSC system, structure, and component

SW service water

TLAA time-limited aging analysis

TS technical specifications

TSP trisodium phosphate

UFSAR updated final safety analysis report

UGS upper guide structure

USE upper-shelf energy

VCT volume control tank

VHP vessel head penetration

xiv
1. INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Arkansas Nuclear One, Unit 2 (ANO-2), as filed by Entergy Operations, Inc. (Entergy,'or the

applicant). By letter dated October 14, 2003, Entergy submitted its application to the U.S.

Nuclear Regulatory Commission (NRC, or the Commission) for renewal of the ANO-2 operating

license for up to an additional 20 years.'; The NRC staff prepared this report, which sumrrinarizes

the results of the staff's'safety review of the renewal application for compliance with the'

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

Power Plants," of the' Code of Federal Regulations (10 CFR Part 54), also known 'as the

License Renewal Rule or Rule. The NRC project manager for the ANO-2 license' renewal

review is Gregory Suber. Mr. Suber may be contacted by calling 301-415-1124, e-mailing

GXS@nrc.oov, or writing to the License Renewal and Environmental Impacts Program, Officeof Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-

0001.

In its October 14, 2003, submittal letter, the applicant 'requested renewal of the operating

license issued under Section 103 of the Atomic Energy Act of 1954, 'as amended (Facility

Operating License Number NPF-6) for a period of 20 years beyond the current license

expiration date of midnight, July 17, 2018. The ANO site is located in southwestern Pope

County, Arkansas, on a peninsula formed by Lake Dardanelle. The NRC issued the ANO-2

construction permit on December 6,1972, and the operating license on September 1, 1978.

The ANO-2 plant consists of a Combusti6n Engineering (CE) pressurized-water reactor (PWR)

unit licensed to generate 3026 megawatts-thermal (MWt), or approximately 1023 megawattselectric (MWe). The updated final safety analysis report (UFSAR) contains details'concerning

the plant and the site.

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

safety issues and an environmental review. The NRC regulations in-10 CFR Parts 54 and 51,

respectively, provide the requirements for these reviews. The NRC bases the safety review for

the ANO-2 license renewal on the applicant's'license renewal application (LRA)'and on the

responses to requests for additional informrati6on(RAIs) from the staff.' The applicant

supplemented its responses to the LRA and RAls during audits, meetings; and in docketed

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

applicant submitted through February 28,:2005, 'which includes'all the information submitted in

support of the LRA. The LRA and all pertinent information and materials, including'the UFSAR

mentioned above, are available to the public for review at the NRC Public Document Room,

11555 Rockville Pike, Roor 01 -F21, Rockville,' Maryland (301 -415-4737/800-397-4209),'or at

Ross Pendergraft Library and Technologj Center at Arkansas Tech University in Russellville,

Arkansas. Materials related to the'LRA'are also available through the NRC's Web site, at

http://www.nrc.gov.

This SER summarizes the results of the staff's 'safety review of the ANO-2 LRA and delineates

the scope of the'techrni6al details the staff 6ofisidered in evaluating'the safety as'pects of its

proposed operation for up to 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

1 -1
provided in NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications

for Nuclear Power Plants," (SRP-LR) issued July 2001.

Sections 2 through 4 of this SER address the staff's evaluation of license renewal issues that it

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

Advisory Committee on Reactor Safeguards (ACRS). Section 6 of this SER addresses the

conclusions of this report.

Appendix A to this SER provides a table that identifies the applicant's commitments associated

with renewing the operating license. Appendix B provides a chronology of the NRC's and the

applicant's principal correspondence related to the review of the application. Appendix C lists

the principal contributors to the SER. Appendix D presents a list of the references. Appendix E

presents an index of the staff's RAIs and the applicant's responses.

In accordance with 10 CFR Part 51, "Environmental Protection Regulations for Domestic

Licensing and Related Regulatory Functions," the staff will prepare a draft for comment and a

final, plant-specific supplement to the generic environmental impact statement (GEIS) that

discusses the environmental considerations related to renewing the license for ANO-2. The

NRC issued NUREG-1437, Supplement 19, "Generic Environmental Impact Statement for

License Renewal of Nuclear Plants: Regarding Arkansas Nuclear One, Unit 2, Draft Report," in

September 2004.

1.2 License Renewal Background

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

licenses to operate commercial power reactors for 40 years. It is possible to renew these

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

basis of economic and antitrust considerations, not because of technical limitations. However,

some individual plant and equipment designs may have been engineered on the basis of an

expected 40-year service life.

In 1982, the NRC held a workshop on nuclear power plant aging, in anticipation of interest in

license renewal. That workshop led the NRC to establish a comprehensive program plan for

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

group concluded that many aging phenomena are readily manageable and do not pose

technical issues that would preclude life extension for nuclear power plants. In 1986, the NRC

published a request for comment on a policy statement that would address major policy,

technical, and procedural issues related to license renewal for nuclear power plants.

In 1991, the NRC published the License Renewal Rule in 10 CFR Part 54. The NRC

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

and to develop experience for establishing implementation guidance. To establish a scope of

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

However, during the demonstration program, the NRC found that many aging mechanisms

occur and are managed during the period of the initial license. In addition, the NRC found that

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

implementation of the Maintenance Rule, which also manages plant aging phenomena. As a

result, the NRC amended the License Renewal Rule in 1995. The amended 10 CFR Part 54

1-2
established a regulatory process that is simpler, more stable, and more predictable than the

previous License Renewal Rule.- In particular, the NRC amended 10 CFR Part 54 to focus on

managing the adverse effects of aging rather than on identifying age-related degradation

unique to license renewal. The NRC intended that the Rule changes would ensure that

important structures, systems, and components (SSCs) will continue to perform their intended

functions during the period of extended operation. In addition, the NRC clarified and simplified

the integrated plant assessment (IPA) process to be consistent with the revised focus on

passive, long-lived structures and components (SCs).

In parallel with these efforts, the NRC pursued a separate rulemaking effort and developed

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

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

(NEPA).

1.2.1 Safety Review

The NRC bases license renewal requirements for power reactors on the following two key

principles:

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

operating plants provide and maintain an acceptable level of safety, with the possible,

exception of the' detrimental effects of aging on the functionality of certain plant SSCs,

and possibly a few other issues related to safety, during the period of extended,

operation.

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

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

In implementing these two principles, 10 CFR 54.4 defines the scope of license renewal as

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

and (3) that are necessary to demonstrate compliance with the NRC's regulations for fire

protection (FP), environmental qualification, pressurized thermal shock, anticipated transients

without scram, and station blackout (SBO).

Pursuant to 10 CFR 54.21 (a), an applicant for a renewed license must review all SSCs within

the scope of the License Renewal Rule to identify SCs subject to an aging management review

(AMR). The SCs subject to an AMR are those that perform an intended function without

moving parts or without a change in configuration or properties, and that are not subject to.

replacement based on qualified life or specified time period. As required by 10 CFR 54.21 (a),

an applicant for a renewed license must demonstrate that the effects of aging will be managed

in such a way that the intended function or'functions of those SCs will be maintained, consistent

with the current licensing basis (CLB), for the period of extended operation. The NRC

considers active equipment, however, to be adequately monitored and maintained by existing

programs. In other words, the detrimental aging effects that may occur for active equipment

are more readily detectable and will be revealed through performance indicators, or the

applicant will identify and correct them through routine surveillance and maintenance. The

surveillance and maintenance'programs for active equipment, as well as other aspects of

maintaining the plant design and licensing basis, are required throughout the period of

1-:3
extended operation. According to 10 CFR 54.21 (d), a supplement to the UFSAR must contain

a summary description of the programs and activities for managing the effects of aging and the

evaluations of time-limited aging analyses for the period of extended operation.

The Rule also requires an applicant to identify and update time-limited aging analyses (TLAAs).

During the design phase for a plant, certain assumptions are made about the length of time the

plant will operate. These assumptions are incorporated into design calculations for several of

the plant's 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 it will adequately manage the

effects of aging on these SSCs for the period of extended operation.

In 2001, 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 an implementation guideline prepared by the Nuclear Energy Institute (NEI) as an

acceptable method for implementing the License Renewal Rule. This guideline is NEI 95-10,

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

Renewal Rule," issued in March 2001. The NRC also prepared the SRP-LR, which it used to

review this application.

The applicant used the process defined in NUREG-1 801, "Generic Aging Lessons Learned

(GALL) Report," issued July 2001. The GALL Report provides the staff with a summary of

staff-approved aging management programs (AMPs) for the aging of many SCs that are

subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the

time, effort, and resources used to review an applicant's LRA will be greatly reduced, thereby

improving the efficiency and effectiveness of the license renewal review process. The GALL

Report summarizes the aging management evaluations, programs, and activities credited with

managing aging for most of the SCs used throughout the industry. It serves as a reference for

both applicants and staff reviewers to quickly identify those AMPs and activities that the staff

has determined will adequately manage aging during the period of extended operation.

1.2.2 Environmental Review

Title 10, Part 51, of the Code of Federal Regulations (10 CFR Part 51) governs environmental

protection regulations. The NRC revised these regulations in December 1996 to facilitate the

environmental review for license renewal. The staff prepared a GEIS, in which the staff

examined the possible environmental impacts associated with renewing licenses of nuclear

power plants. For certain types of environmental impacts, the GEIS establishes generic

findings that are applicable to all nuclear power plants. Appendix B to Subpart A of

10 CFR Part 51 identifies these generic findings as Category 1 issues. Pursuant to 10 CFR

51.53(c)(3)(1), an applicant for license renewal may incorporate these generic findings in its

environmental report. The applicant must include analyses of those environmental impacts that

it must evaluate on a plant-specific basis (Category 2 issues) in the environmental report, in

accordance with 10 CFR 51.53(c)(3)(ii).

In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plantspecific review of the environmental impacts of license renewal, including whether there was

new and significant information not considered in the GEIS. A public meeting took place on

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February 3, 2004, in Russeliville, Arkansas, as part of the NRC's scoping process to identify

environmental issues specific to the plant. On August 30, 2004, the NRC documented the

results of the environmental review (and a preliminary recommendation with respect to the

license renewal action) in its draft plant-specific supplement to the GEIS, which was discussed

at a separate public meeting held on October 19, 2004, in Russellville, Arkansas. After

considering comments on the draft, the NRC will prepare and publish a final plant-specific

supplement to the GEIS. These documents are published separate from this SER.

1.3 Principal Review Matters

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

requirements for renewing operating licenses for nuclear power plants. The staff performed its

technical review of the ANO-2 LRA in accordance with Commission'guidance and the

requirements of 10 CFR Part 54. Furthermore, 10 CFR 54.29 describes the standards for

renewing a license. This SER describes the results of the staff's safety review.

In 10 CFR 54.19(a), the Commission requires a license renewal applicant to submit general

information. The applicant provided this general information in Section 1 of its LRA for ANO-2,

submitted by letter dated October 15, 2003. vThe staff finds that the applicant has submitted the

information required by 10 CFR 54.19(a) in Section 1 of the LRA.

In 10 CFR 54.19(b), the Commission 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." The applicant stated the following in its LRA regarding this

issue:

The current indemnity agreement for ANO-2 states in Article VII that the

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

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

the Attachment to the indemnity agreement as revised by Amendment No. 6,;

lists ANO-2 operating license number NPF-6. Entergy Operations requests 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 ANO-2 facility operating license sought in

this application. In addition, should the license number be changed upon

issuance of the renewal license, Entergy Operations requests that conforming

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

indemnity agreement as appropriate.

The staff intends to maintain the license numbers on issuance of the renewed licenses.

Therefore, conforming changes to the indemnity agreement are not necessary, and the

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

In 10 CFR 54.21, the Commission requires that each application for a renewed license for a

nuclear facility must contain (1) an IPA, (2) a description of CLB changes during the staff's

review of the application, (3) an evaluation of TLAAs, and (4) an UFSAR supplement. Chapters

3 and 4, and Appendices A and B, of the LRA address the license renewal requirements of 10

CFR 54.21 (a), (c)), and (d), respectively.

,1-5
- - -

In 10 CFR 54.21 (b), the Commission requires that each year following submittal of the

application, and at least 3 months before the scheduled completion of the staff's review, the

applicant must submit an amendment to the renewal application. In the amendment, the

applicant must identify any change to the CLB of the facility that materially affects the contents

of the LRA, including the UFSAR supplement.

In accordance with 10 CFR 54.22, an applicant must include in the LRA any technical

specification changes or additions necessary to manage the effects of aging during the period

of extended operation. In Appendix D to the LRA, the applicant stated that no changes to the

ANO-2 technical specifications are necessary. This satisfies the requirement specified in 10

CFR 54.22.

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

accordance with the NRC's regulations and the guidance provided by the SRP-LR. Sections 2,

3, and 4 of this SER document the staff's evaluation of the technical information.

The staff will document its evaluation of the environmental information required by

10 CFR 54.23 in the final plant-specific supplement to the GEIS that specifies the

considerations related to renewing the license for ANO-2. The staff will prepare this

supplement separate from this SER. As required by 10 CFR 54.25, the ACRS will issue a

report to document its evaluation of the staff's LRA review and the associated SER. Section 5

of this SER will incorporate this ACRS report. Section 6 of this SER will document the findings

required by 10 CFR 54.29.

1.4 Interim Staff Guidance

The license renewal program is a living program. The NRC staff, industry, and other interested

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

lessons learned are intended to conform to the NRC's performance goals of maintaining safety,

improving effectiveness and efficiency, reducing regulatory burden, and increasing public

confidence. The NRC documents the lessons learned in interim staff guidance (ISG)

documents that it issues to the public for comment, modifies as necessary to resolve

comments, reissues in final, and makes available for use by the staff and interested

stakeholders until the improved license renewal guidance documents are revised.

The following provides the current set of relevant ISGs that the staff has issued, and the SER

sections in which the staff addresses the issues:

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ISG Issue 1 Purpose ' SER Section

(Approved ISG No.) | I_|__,

How to credit plant programs and To clarify that GALL report N/A

activities for license renewal contains one, though not the

(ISG-01) only, acceptable way to

'determine adequacy of plant

programs and activities for

license renewal

Station Blackout Scoping The License Renewal Rule, at 2.5.2

(ISG-2) 10 CFR 54.4(a)(3), includes 3.6.2.3.1

10 CFR 50.63(a)(1) (SBO).

The SBO rule requires that a

plant must withstand and recover

from an SBO event. The

recovery time for offsite power is

much faster than that of

emergency diesel generators.

The offsite power system should

be included within the scope of

license renewal.

Concrete Aging Management Lessons learned from the GALL 3.5.2.2

Program (ISG-3) ' demonstration project indicate 3.5.2.3.1

thatithe GALL Report is not clear

whether concrete needs any

AMPs.' -

;1-7
- -

ISG Issue 1 Purpose l SER Section

(Approved ISG No.) l l

Fire Protection System Piping (ISG- The ISG clarifies the staff 3.0.3.2.4

4) position for wall thinning of FP

piping system in GALL AMPs

XI.M26 and XI.M27.

The new position states that

there is no need to disassemble

FP piping, as oxygen can be

introduced in the FP piping which

can accelerate corrosion.

Instead, licensees should use a

nonintrusive method, such as

volumetric inspection.

Licensees should test the

sprinkler heads every 50 years

and 10 years after initial service.

The ISG eliminates Halon/carbon

dioxide system inspections for

charging pressure, valve lineups,

and automatic mode of operation

test from the GALL Report, as

the staff considers these test

verifications to be operational

activities.

1-8
I

ISG Issue I Purpose | SER Section

(Approved ISG No.)

Identification and Treatment of The ISG includes the fuse holder 3.6.2.4.5

Electrical Fuse Holders (ISG-5) AMR and AMP (i.e., same as

terminal blocks and other

electrical connections).

The position includes only fuse

h6lders that are not inside the

enclosure of active components

(e.g., inside of switchgears and

inverters).

Operating experience finds that

metallic clamps (spring-loaded

clips) have a history of agerelated failures from aging

stressors such as vibration,

thermal cycling, mechanical

stress, corrosion, and chemical

'contamination.

The staff finds that visual

inspection'of fuse clips is not

sufficient to detect the aging

effects from fatigue, mechanical

stress, and vibration.

The ISG Process (ISG-8) To update and establish the N/A

interim staff guidance process.

License Renewal Application To standardize license renewal N/A

Format (ISG-10) application format for 2003

applicants

Environmental Fatigue for To review the aging management N/A

Carbon/Low-Alloy Steel (ISG-1 1) of environmental fatigue in the

ISG process, as agreed at

September 18, 2002, meeting

1.5 Summary of Open Items

Open items are items for which the applicant has not presented a sufficient basis for resolution.

The draft SER was issued on November 5, 2004 with no open items. No subsequent open

items were identified in the preparation of the final SER.

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1.6 Summary of Confirmatory Items

Confirmatory items are items for which the staff and the applicant have reached a satisfactory

resolution, but the applicant has not yet formally submitted the resolution to the staff. The draft

SER was issued on November 5, 2004 with no confirmatory items. No subsequent

confirmatory items were identified in the preparation of the final SER.

1.7 Summary of Proposed License Conditions

As a result of the staff's review of the ANO-2 LRA, including the additional information and

clarifications submitted subsequently, the staff identified three proposed license conditions.

The first license condition requires the applicant to include the FSAR Supplement required by

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

of the renewed license.

The second license condition requires that the future activities identified in the FSAR

Supplement be completed prior to entering the period of extended operation.

The third license condition is as follows:

All capsules in the reactor vessel that are removed and tested must meet the

test procedures and reporting requirements of ASTM E 185-82 to the extent

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

to the capsule withdrawal schedule, including spare capsules, must be approved

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

maintained for future insertion.

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2. STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

2.1.1 Introduction

In Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power

Plants," of the Code of Federal Regulations, (10 CFR Part 54), also referred to as the Rule,

10 CFR 54.21, "Contents of Application-Technical Information," requires that each application

for license renewal contain an integrated plant assessment (IPA). Furthermore, the IPA must

list and identify those structures and components (SCs) that are subject to an aging

management review (AMR) from the structures, systems, and components (SSCs) that are

within the scope of license renewal, in accordance with 10 CFR 54.4.

In Section 2.1, "Scoping and Screening Methodology," of the license renewal application (LRA),

the applicant described the scoping and screening methodology used to identify SSCs at

Arkansas Nuclear One, Unit 2 (ANO-2), that are within the scope of license renewal and SCs

that are subject to an AMR. The staff reviewed the applicant's scoping and screening

methodology to determine if it meets the scoping requirements stated in 10 CFR 54.4(a) and

the screening requirements stated in 10 CFR 54.21.

In developing the scoping and screening methodology for the ANO-2 LRA, the applicant

considered the requirements of the Rule, the Statements of Consideration (SOC) for the Rule,

and the guidance presented by the Nuclear-Energy Institute (NEI), in NEI 95-10, Revision 3,

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

Renewal Rule," issued March 2001. In addition, the applicant also considered the U.S. Nuclear

Regulatory Commission (NRC) staff's correspondence with other applicants and with the NEI in

the development of this methodology.

2.1.2 Summary of Technical Information In the Application

Sections 2.0 and 3.0 of the LRA provide the technical information required by 10 CFR 54.21 (a).

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

meet the license renewal scoping criteria under 10 CFR 54.4(a), as well as the process used to

identify the SCs that are subject to an AMR as required by 10 CFR 54.21 (a)(1).

Additionally, Section 2.2, "Plant Level Scoping Results"; Section 2.3, "System Scoping and

Screening Results: Mechanical"; Section 2.4, 'Scoping and Screening Results: Structures";

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

Systems," of the LRA amplify the process that the applicant used to identify the SCs that are

subject to an AMR. Chapter 3 of the LRA, "Aging Management Review Results," contains

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"; and Section 3.6,

"Electrical and Instrumentation and Controls."- Chapter,4 of the LRA, 'Time-Limited Aging

Analyses," contains the applicant's identification and evaluation of time-limited aging analyses

(TLAAs).

2-1
2.1.2.1 Scoping Methodology

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

In Sections 2.1.1, "Scoping Methodology," and 2.1.1.1, "Application of Safety-Related Scoping

Criteria," of the LRA, the applicant discussed the scoping methodology with regard to safetyrelated criteria in accordance with 10 CFR 54.4(a)(1). With respect to the safety-related

criteria, the applicant stated that the SSCs within the scope of license renewal include safetyrelated SSCs that it identified by a review of plant-specific information to determine if they meet

the criteria of 10 CFR 54.4(a)(1).

The applicant maintained a component-level database which identified the component safety

classification. The safety-related classification uses the same definition as that stated in

10 CFR 54.4. The ANO-2 definition of safety related used to develop and maintain the

component-level Q-list includes the SSCs that are relied on to remain functional during or after

design-basis events to ensure the following:

* the integrity of the reactor coolant pressure boundary

* the capability to shut down the reactor and maintain it in a safe-shutdown condition

* the capability to prevent or mitigate the consequences of accidents which could result in

potential offsite exposures comparable to the guideline exposures of 10 CFR Part 100,

"Reactor Site Criteria"

In addition to the guidelines of 10 CFR 100.1 1, the safety-related criteria of

10 CFR 54.4(a)(1)(iii) includes reference to the dose guidelines of 10 CFR 50.34(a)(1) and

10 CFR 50.67(b)(2).

The LRA indicates that the applicant determined the SSCs which perform safety functions by

reviewing the ANO-2 component-level Q-list and the system and structure functions. If one or

more of the three criteria were met, the applicant determined the function to be a safety

intended function and included the corresponding system or structure within the scope of

license renewal as safety related. The applicant used the plant design-basis documents,

including the safety analysis report (SAR) and the upper level design documents, to identify the

system functions and verify the Q-list identification of safety-related components. The applicant

elected to designate some components that do not perform any of the functions of 10 CFR

54.4(a)(1) as safety-related because of plant-specific considerations or preferences. Therefore,

certain components may not meet the criteria of 10 CFR 54.4(a)(1), although the component

was designated as safety related for plant-specific reasons. The LRA states that very few

components meet this exception and notes that the applicant still evaluated the systems and

structures containing these components for inclusion in the scope of license renewal using the

criteria of 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3).

In Sections 2.1.1 and 2.1.1.2, "Application of Criterion for Nonsafety-Related SSCs Whose

Failure Could Prevent the Accomplishment of Safety Functions," of the LRA, the applicant

discussed the scoping methodology with regard to the nonsafety-related criteria, in accordance

with 10 CFR 54.4(a)(2). With respect to the nonsafety-related criteria, the applicant stated, in

part, that it performed a review to identify the nonsafety-related SSCs whose failure could

2-2
prevent satisfactory accomplishment of the safety-related intended functions identified in

10 CFR 54.4(a)(1).

The LRA states that the applicant identified nonsafety-related SSCs whose failure could prevent

satisfactory accomplishment of a safety function. 'The applicant considered the impacts of

non'safety-related SSC failures as either functional or spatial. In a functional failure, the failure

of an SSC to perform its normal function'impacts a safety function. In a spatial failure, a safety

function is impacted by the loss of structural or 'mechanical integrity of an SSC in physical

proximity to a safety-related component.

Functional Failures of Nonsafetv-Related SSCs. The LRA states that, with few exceptions, the

applicant classified SSCs as safety related if they are required to perform a function in support

of other safety-related components and included them in the scope of license renewal, per

10 CFR 54.4(a)(1). For the few exceptions where nonsafety-related equipment is required to

remain functional in support of a safety function, the applicant included the supporting systems

within the' scope as nonsafety-related SSCs affecting safety-related SSCs. The applicable

sections of the SAR, technical specifications, Maintenance Rule'scoping documents, and

design-basis documents provided the system information to determine the appropriate systems

and structures in this category.

The applicant determined that, for piping systems, the nonsafety-related piping and supports,

up to and including the first equivalent anchor beyond the safety/nonsafety-related interface,

are subject to an'AMR. In addition, nonsafety-related portions of safety-related systems

downstream of the first anchor are subject to an AMR if they have the potential for spatial

interaction with safety-related SSCs. - i

Spatial Failures of Nonsafetv-Related SSCs.: The applicant determined that components

meeting the scoping criteria of 10 CFR 54.4(a)(2) are either nonsafety-related SSCs directly

connected to safety-related SSCs (typically'piping systems), or nonsafety-related SSCs with the

potential for spatial interaction with safety-related SSCs. The LRA states that protective

features (e.g', whip restraints, spray shields;'-supports, and barriers) were installed to protect

safety-related SSCs against spatial interaction with nonsafety-related SSCs. Such protective

features credited in the plant design are included within the scope of license renewal and are

subject to an AMR. Where those protective features provide adequate protection, the applicant

excluded the' nonsafety-related system itself from the scope of license renewal. Protective

features are'typically associated with a structure and are addressed in the structural AMR. The

applicant determined that the different modes of spatial interaction include the following:

The first mode is physical impact. 'Nonsafety-related supports for nonseismic or seismic

Category Il/I piping systems with a potential for spatial interaction with safety-related

SSCs are subject to an AMR based on the criteria of 10 CFR 54.4(a)(2). These

supports are addressed in a commodity fashion within the civil/structural section of the

LRA. The LRA states that, based on earthquake experience data that include aged

pipe, the following conclusions can be-drawn:

- ; : - '

- No experience data exist of welded steel pipe segments falling because of a

strong-motion'earthquake.- ;

2-3
-Ea

- Falling of piping segments is extremely rare and only occurs when the supports

fail. As long as the effects of aging on the supports for piping systems are

managed, the applicant did not consider the falling of piping sections to be

credible, and the piping section itself is not within scope for 10 CFR 54.4(a)(2)

because of the physical impact hazard. Internal or external events, such as

failure of rotating equipment, can generate missiles. Inherent nonsafety-related

features that protect safety-related equipment from missiles require an AMR

based on the criteria in 10 CFR 54.4(a)(2). The overhead-handling systems (i.e.,

cranes), whose structural failure could result in damage to any system that could

prevent the accomplishment of a safety function, meet the criteria of

10 CFR 54.4(a)(2) and are within the scope of license renewal.

The second mode includes pipe whip, jet impingement, or harsh environments. The

LRA states that the site-specific analyses of high-energy line breaks (HELB) and

medium-energy line breaks address pipe whip, jet impingement, and harsh environment

effects on safety-related equipment. The LRA states that if a HELB analysis assumes

that a nonsafety-related piping system does not fail or assumes failure only at specific

locations, then that piping system is within the scope of license renewal per

10 CFR 54.4(a)(2) and subject to an AMR. This provides reasonable assurance that

those assumptions remain valid through the period of extended operation.

The third mode includes leakage, spray, or flooding. The LRA states that moderateand low-energy systems have 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 their required safety function are within the scope of license renewal and

subject to an AMR. The LRA states that no credible aging effects of air and gas

(nonliquid) systems exist, and they cannot adversely affect safety-related SSCs by

leakage or spray. Operating experience indicates that nonsafety-related systems

containing only air or gas have experienced no failures from aging that could impact the

ability of safety-related equipment to perform required safety functions. These systems

are not within the scope of license renewal according to the scoping criteria of

10 CFR 54.4(a)(2).

The LRA states that the applicant considered nonsafety-related systems and nonsafety-related

portions of safety-related systems containing steam or liquid that are near safety-related

equipment to be within scope and subject to an AMR for 10 CFR 54.4(a)(2). Pressure

boundary failures of these systems could result in the nonsafety-related piping spraying or

leaking on safety-related equipment. The LRA states that consideration of hypothetical failures

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

(CLB) and that have not been previously experienced is not required. Long-term exposure to

conditions resulting from a failed nonsafety-related SSC (e.g., leakage or spray) is not

considered credible. The applicant indicated that operators would detect leakage or spray from

liquid-filled low-energy systems during their routine rounds or system walkdowns long before it

could impact the performance of safety-related equipment. The LRA states that walls, curbs,

dikes, doors, and other structures that provide flood barriers to safety-related SSCs require an

AMR based on the criteria of 10 CFR 54.4(a)(2). The applicant included these as part of the

building structure and evaluated them in the civil/structural AMR.

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In Sections 2.1.1 and 2.1.1.3, "Application of Criterion for Regulated Events," of the LRA, the

applicant discussed the scoping methodology'as it relates to the regulated event criteria in

accordance with 10 CFR 54.4(a)(3). The LRA states that the scope of license renewal includes

those SSCs relied on in safety analyses or plant evaluations to perform a function that

demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48),

environmental qualification (EQ) (10 CFR 50.49), pressurized thermal shock (PTS)

(10 CFR 50.61), anticipated transients without scram (ATWSs) (10 CFR 50.62), and station

blackout (SBO) (10 CFR 50.63).

Fire Protection. The LRA states that systems and structures within the scope of license

renewal for fire protection include equipment based on functional requirements defined in

10 CFR 50.48 and Appendix R.- The SSCs credited with fire prevention, detection, and

mitigation in areas containing equipment important to the safe operation of the plant are within

scope for license renewal. To establish this scope of equipment, the applicant performed a

detailed review of the ANO-2 CLB for fire protection. Based on this review, the applicant

determined the intended functions performed in support of 10 CFR 50.48 requirements. The

applicant included the SSCs relied on in safety analyses or plant evaluations to perform an*

intended function and demonstrate compliance with NRC regulations for fire protection within

the scope of license renewal, in accordance with the criteria of 10 CFR 54.4(a)(3).

Environmental Qualification. The LRA states that 10 CFR 50.49 defines electric equipment

important to safety that is required to be environmentally qualified to mitigate certain accidents

that result in harsh environmental conditions in the plant. The LRA states that 10 CFR 50.49

codifies requirements for the EQ of electrical equipment that has been presented in other

regulatory documents, such as NRC Office of Inspection and Enforcement (IE) Bulletin 79-01 B,

and the ANO-2 EQ program satisfies these requirements. The applicant used a bounding

scoping approach for electrical equipment. iElectrical systems and electrical equipment in

mechanical systems, subject to the regulation, are included as within the scope of license

renewal. The applicant included the SSCs relied on in safety analyses or plant evaluations to

perform an intended function and demonstrate compliance with NRC regulations for EQ within

the scope of license renewal, in accordance with the criteria of 10 CFR 54.4(a)(3). -

Pressurized Thermal Shock. The LRA states that the rule concerning PTS, 10 CFR 50.61,

requires that licensees evaluate the reactor vessel belt!ine materials against specific criteria to

ensure protection from brittle fracture. For ANO-2, the limiting reference temperatures are well

below the screening criteria. As a result, nio flux reduction programs or modifications to

equipment, systems, or operation are necessary to prevent potential failure of the reactor.

vessels. The only system relied upon to meet the PTS regulation is the reactor coolant system

(RCS), which contains the reactor vessel.: No structures are relied upon to meet the PTS

regulation. The applicant included the SSCs relied on in safety analyses or plant evaluations to

perform an intended function and demonstrate compliance with NRC regulations for PTS within

the scope of license renewal, in accordance with the criteria of 10 CFR 54.4(a)(3).

Anticipated Transients Without Scram. The LRA states that an ATWS is an anticipated

operational occurrence that is accompanied by a failure of the reactor trip system to shut down

the reactor. The ATWS rule, 10 CFR 50.62, requires specific improvements in the design and

operation of commercial nuclear power facilities to reduce the probability of failure to shut down

the reactor following anticipated transients and to mitigate the consequences of an ATWS

event. Based on the ANO-2 CLB for ATWS,,the applicant determined the intended functions

-2-5
- a

supporting 10 CFR 50.62 requirements. Since the scope of equipment required by

10 CFR 50.62 extends from sensor output to the final actuation device, the plant systems that

support compliance with the ATWS rule are electrical and instrumentation and control (I&C)

systems. The applicant used a bounding scoping approach for electrical equipment. Electrical

systems are included within the scope of license renewal, and the applicant evaluated the

electrical equipment in mechanical systems with the electrical systems. The applicant included

the SSCs relied on in safety analyses or plant evaluations to perform an intended function and

demonstrate compliance with NRC regulations for ATWS within the scope of license renewal, in

accordance with the criteria of 10 CFR 54.4(a)(3).

Station Blackout. According to the LRA, to comply with 10 CFR 50.63, ANO-2 relies upon

equipment to ensure the cooling of the reactor core and maintenance of the containment

integrity using the station batteries and the alternate alternating current (ac) diesel before offsite

or onsite ac power is restored. Based on the review of the ANO-2 current licensing bases for

SBO, the applicant identified the equipment performing intended functions required for

compliance with 10 CFR 50.63. The applicant included the systems and structures relied upon

to restore the offsite ac power (including the onsite portion of the offsite power sources) and

onsite ac power within the scope of license renewal for SBO. In addition to the plant electrical

systems, certain switchyard components required to restore offsite power are included. The

SSCs relied on in safety analyses or plant evaluations to perform an intended function and

demonstrate compliance with NRC regulations for SBO are included within the scope of license

renewal, in accordance with the criteria of 10 CFR 54.4(a)(3).

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In Section 2.1.1 of the LRA, the applicant stated that it reviewed information derived from the

applicable sections of the SAR, technical specifications, Maintenance Rule scoping documents,

upper level documents, and ANO topical reports for the NRC regulations identified in

10 CFR 54.4(a)(3) during the license renewal scoping and screening process. The applicant

used this information to identify the functions performed by plant systems and structures. The

applicant then compared these functions with the scoping criteria in 10 CFR 54(a)(1-3) to

determine if the associated plant system or structure performs a license renewal intended

function. The applicant also used these sources develop the list of SSCs subject to an AMR.

2.1.2.2 Screening Methodology

Following the determination of SSCs within the scope of license renewal, the applicant

implemented a process for determining which SCs are subject to an AMR, in accordance with

the requirements of 10 CFR 54.21(a)(1). In Section 2.1.2, "Screening Methodology,' of the

LRA, the applicant discussed these screening activities as they relate to the SCs that are within

the scope of license renewal.

2.1.2.2.1 Mechanical Component Screening Methodology

Following component-level scoping for mechanical systems, the applicant performed screening

to identify those mechanical components that are subject to an AMR. The applicant stated in

LRA Section 2.1.2.1, "Screening of Mechanical Systems," that within the system, long-lived

passive components that perform or support an intended function without moving parts or a

change in configuration or properties are subject to an AMR. In the case of valves, pumps, and

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housings for fans and dampers, the applicant determined the valve bodies, pump casings, and

housings that perform an intended function by maintaining the pressure boundary and are

therefore subject to an AMR. - at

If the component is not subject to replacement based on qualified life or specified time period,

the applicant considered it to be long-lived.- Replacement programs are based 6n vendor

recommendations, plant experience, or other means that establish a specific service life,

qualified life, or replacement frequency under a controlled program. The applicant did not

include components that are not long-lived in the AMR.

2.1.2.2.2 Structural Component Screening Methodology

Following component-level scoping for structures, the applicant performed screening to identify

those civil/structural components that are subject to an AMR. In LRA Section 2.1.2.2,

"Screening of Structures," the applicant described the methodology used to screen

civil/structural components.

The LRA states that for each structure within the scope of license renewal, the applicant

evaluated the structural components and commodities to determine those subject to an AMR.

The screening process for structural components and commodities involved a review of designbasis documents to identify specific structural components and commodities that constitute the

structure. Structural components or commodities subject to an AMR are those that perform an

intended function without moving parts or a change in configuration or properties (i.e., passive),

and are not subject to replacement based on qualified life or specified time period (i.e., long-,

lived). Since structures are inherently passive, and with few exceptions are long-lived, the

screening of structural components and commodities was based primarily on whether they

perform an intended function.

Structural Component and Commodity Groups. -.The LRA states that structural components and

commodities often have no unique identifiers, such as those given to mechanical components.

Therefore, grouping structural components and commodities based on materials of construction

provides a practical means of categorizing them for AMRs. The applicant categorized structural

components and commodities according to the following groups, based on materials of

construction:

* steel

* threaded fasteners

* concrete

* fire barriers - . * elastomers

* earthen structures

* Teflon -

Evaluation Boundaries. The applicant generally categorized structural components and

commodities that are attached to a structure or reside within a structure as either component

supports or other structural members: , ,.

* The applicant established the evaluation boundaries for mechanical component

supports in accordance with rules governing inspection of component supports (i.e.,

2-7
- z

American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,

Section Xl, Subsection IWF). Article IWF-3100, Figure IWF-1300-1, defines component

support examination boundaries for integral and nonintegral (i.e., mechanically

attached) supports. In general, the support boundary extends to the surface of the

building structure but does not include the building structure. Furthermore, the support

boundary extends to include nonintegral attachments to piping and equipment but

excludes integral attachments to the same.

* Supports for electrical components include cable trays and conduit supports, electrical

panels, racks, cabinets, and other enclosures. The evaluation boundary for these items

includes supporting elements, such as mechanical or integral attachments to the

building structure.

* Evaluation boundaries for other structural members which carry dynamic loads caused

by postulated design-basis events are consistent with the method for establishing

boundaries for supports specified above. That is, the boundary includes the structural

component and the associated attachment to the building structure. The applicant

considered the portion of the attachment embedded in the building structure as part of

the structure.

Intended Function. The applicant evaluated structural components and commodities to

determine intended functions as they relate to license renewal. Unlike mechanical equipment

for which both system-level and component-level intended functions are defined, the intended

functions for structures are typically based on a simple set of functions that apply both to the

structure and to its components and commodities. NEI 95-10 provides guidelines for

determining the intended functions of structures, structural components, and commodities for

purposes of license renewal.

2.1.2.2.3 Electrical/Instrumentation and Control Component Screening Methodology

Following system-level scoping, the applicant performed screening to identify those

electrical/l&C components that are subject to an AMR. In LRA Section 2.1.2.3, "Electrical and

Instrumentation and Control Systems," the applicant described the methodology used to screen

civilstructural components.

Passive Screening. The LRA states that Appendix B, "Typical Structure, Component and

Commodity Groupings and Active/Passive Determinations for the Integrated Plant

Assessment," to NEI 95-10 identifies electrical commodities considered to be passive. The

applicant identified and cross-referenced the ANO-2 electrical commodity groups to the

appropriate NEI 95-10 commodity, which identified the passive commodity groups.

The applicant identified two passive electrical and I&C commodity groups that meet the

10 CFR 54.21 (a)(1)(1) criterion (i.e., components that perform an intended function without

moving parts or without a change in configuration):

(1) cables and connections, bus, and electrical portions of electrical and l&C penetration

assemblies

(2) high-voltage insulators

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The applicant considered the pressure bounidary function that may be associated with some

electrical and l&C components identified in Appendix B to NEI 95-10 (e.g., flow elements,

vibration probes) in the mechanical AMRs, as applicable. In addition, electrical components

which are supported by structural commodities' (e.g., cable trays, conduit and cable trenches)

are included in the structural AMRs.-

Long-Lived Screening. The LRA states thatelectrical components included in the

Environmental Qualification Program per10 CFR 50.49 are replaced based on qualified life

and, therefore, do not meet the long-lived criterion of 10 CFR 54.21 (a)(1)(ii) and are not subject

to an AMR. Some insulated cables and connections and most electrical penetration assemblies

are included in the Environmental Qualification Program and are not subject to an AMR. The

applicant did not screen out any other passive, non-EQ electrical components per the long-lived

criterion; therefore, they are subject to an AMR.;

2.1.3 Staff Evaluation

As part of its review of the applicant's LRA,:the NRC staff evaluated the scoping and screening

activities'described in Section 2.1 to ensure that the applicant described a process for

identifying SSCs that are within the scope of license renewal, in accordance with the

requirements'of 10 CFR 54.4(a)(1-3). The-staff evaluated Sections 2.2,2.3, 2.4, and 2.5 to

Assure that the applicant described a process'for determining structural, mechanical, and

electrical components at ANO-2 that are subject to an AMR for license renewal, in accordance

with the requirements of 10 CFR 54.21 (a)(1-2).

In addition, the staff conducted a scoping and screening methodology audit at ANO-2 from

January 20-23, 2004. The results of the audit were'documented in the ANO-2 Trip Report

issued on October 7, 2004 (ML0428104440). ' The audit focused on ensuring that the applicant

developed and implemented adequate guidance to conduct the scoping and screening of SSCs

in accordance with the methodologies ddsbribed in the application and the requirements of the

Rule. The audit team reviewed implementation procedures and engineering reports which

describe the'scoping and screening methodology'implemented by the applicant. In addition,

the audit team conducted detailed discussions with the cognizant engineers on the

implementation and control of the program) It reviewed administrative control documentation

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

process. The audit team further reviewed 'a saniple of system scoping and screening results

reports for the main feedwater, emergency feedwater, and emergency diesel generator (EDG)

to ensure that the applicant appropriately implemented the methodology outlined in the : :

administrative controls. The team found the results reports to be consistent with the CLB, as

described in the supporting design documrientation.

2.1.3.1 Scoping Methodology

The audit team reviewed implementation procedures and engineering reports that describe the

scoping'and screening methodology implemented by the applicant. These procedures include

LRPG-03,'"System and Structure Scoping Guidelines"; LRPG-04, "Mechanical System

Screening and Aging Management Reviews"; LRPG-05, "Electrical Systems Scoping,

Screening and Aging Management Reviews"; LRPG-06, "Structural Screening and Aging

i_2-9
Management Reviews"; A2-ME-2003-001-1, "Aging Management Review of Nonsafety-related

Systems and Components Affecting Safety-related Systems"; ULD-0-TOP-01, "Environmental

Qualification"; ULD-0-TOP-02, 'Fire Protection Topical"; ULD-0-TOP-1 9, Station Blackout";

ULD-2-SYS-34, "DSS DEFAS Reactor Trip System (ATWS)"; SAR Section 5.2.4.3.2,

"Pressurized Thermal Shock"; ULD-0-TOP-22, "ANO Component Classification Topical";

LRPG-01, "Project Plan"; A2-ME-2003-001-1, "Aging Management Review of NonsafetyRelated"; and LI-11 0, "Commitment Management Program.' The team found that the scoping

and screening methodology instructions are consistent with Section 2.1 of the LRA and are of

sufficient detail to provide the applicant's staff with concise guidance on the scoping and

screening implementation process to be followed during the LRA activities. In addition to the

implementing procedures, the audit team reviewed supplemental design information, including

design-basis documents, system drawings, and selected licensing documentation, which the

applicant relied upon during the scoping and screening phases of the review. The team found

these design documentation sources to be useful for ensuring that the initial scope of SSCs

identified by the applicant is consistent with the CLB of ANO-2.

The applicant compiled lists of systems and structures from sources, such as the component

and maintenance databases; design-basis documents; the Updated Final Safety Analysis

Report (UFSAR); site architectural, civil, and piping and instrumentation diagrams (P&lDs);

Maintenance Rule documents; regulatory compliance reports; Environmental Qualification

Program documents; fire hazard analysis reports; safety evaluation reports (SERs); and the

probabilistic risk assessment summary report. The applicant used these sources to identify the

intended safety functions of the systems and structures in accordance with the criteria of

1 0 CFR 54.4(a)(1-3). The applicant used the component database system, "Passport," which

identifies safety-related, Q-list components. This information was transferred to the License

Renewal Information System and used to identify those systems containing safety-related and

regulated event supporting components to be considered within scope for license renewal. The

applicant documented the scoping results in accordance with LRPG-03.

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

1 0 CFR 54.4(a)(1). Pursuant to 10 CFR 54(a)(1), the applicant must consider as within the

scope of license renewal all safety-related SSCs which are relied upon to remain functional

during and following design-basis events to ensure (1) the integrity of the reactor coolant

pressure boundary, (2) the ability to shut down the reactor and maintain it in a safe-shutdown

condition, or (3) the capability to prevent or mitigate the consequences of accidents which could

result in potential offsite exposures comparable to those referenced in 10 CFR 50.34(a)(1),

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

As part of its review of the applicant's scoping methodology, the audit team evaluated a sample

of the license renewal database 10 CFR 54(a)(1) scoping results, examined a sample of the

analyses and documentation to support these reviews, and discussed the methodology and

results with the applicant's personnel responsible for these evaluations. The team verified that

the applicant identified and used pertinent engineering and licensing information in order to

determine the SSCs required to be within scope, in accordance with the 10 CFR 54.4(a)(1)

criteria. On the basis of this sample review and discussions with the applicant, the audit team

determined that the applicant's methodology for identifying systems and structures meeting the

scoping criteria of 10 CFR 54(a)(1) is adequate.

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The audit team noted that 10 CFR 54.4(a)(1)(iii) requires that the applicant consider within the

scope of license renewal those SSCs that ensure the capability to prevent or mitigate the

consequences of accidents which could result in potential offsite exposures comparable to

those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11. In Section

2.1.1.1 of the LRA, the applicant stated that, because of plant-unique considerations or

preferences, it designated some components that do not perform any of the functions meeting

the requirements of 10 CFR 54.4(a)(1) as safety related, such that certain items classified as

safety related in the facility database do not perform any of the safety-related intended

functions of 10 CFR 54.4(a)(1). The staff requested a description of the process used during

license renewal scoping activities to disposition components classified as safety related that do

not perform a safety-related intended function. In particular, the staff requested (a) a

description of any components or structures classified as safety related in the facility safety

classification database that are not included within the scope of license renewal under the

10 CFR 54.4(a)(1) criteria and (b) the process'used to reconcile the facility database safety

classification information with scoping intended function determinations. The staff documented

this as Request for Additional Information (RAI) 2-1.3.

The applicant responded in a letter to the NRC dated May 19, 2004:

a. For the majority of mechanical components, the safety classification in

the ANO-2 component database was consistent with the determination

that the components required aging management review for license

renewal. The following individual mechanical components were listed in

the component database as safety-related but did not support the safety

functions identified under the 10 CFR 54.4(a)(1) criteria or meet the

10 CFR 54.4(a)(2) or (a)(3) criteria and, therefore, did not require aging

management review.

Safety-related instrument air solenoid valves do not require aging

management review since the passive pressure boundary function is not

required for the system intended functions to be met. The components

supplied by the instrument air solenoid valves fail to the safe position on

loss of air pressure, so pressure boundary integrity of the solenoid valves

that supply instrument air'is not required to accomplish system intended

functions.

The emergency diesel generator air compressors and their relief valves

are classified as safety-related in the database, but the compressors are

not required to operate during'the'starting of the diesel. There is

adequate air stored in tanks to ensure the diesel starts without the

compressors. The compressors and relief valves are not part of the tank

pressure boundary. These components are conservatively classified in

the database, but are not required to accomplish system intended

functions.

Flexible stainless steel piping to reactor coolant pump seal pressure

transmitters'are shown as'safety-related in the database, but are

connected to nonsafety-related piping and transmitters and do not have a

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safety function. These components are conservatively classified in the

database, but are not required to accomplish system intended functions.

The review identified a few components identified as safety-related in the

database where safety classification changes are pending that will

change the classification to nonsafety-related.

There were no structures identified as safety-related in the component

database that were not included in the structural aging management

reviews.

b. As described in LRA Section 2.1.1, the process used to determine the

systems and structures in the scope of license renewal for ANO-2

followed the recommendations of Nuclear Energy Institute (NEI) 95-10.

Functions for the structures and mechanical systems were identified

based on reviews of applicable plant licensing and design documentation.

The applicable sections of the safety analysis report, technical

specifications, maintenance rule scoping documents, upper level

documents, and ANO topical reports for the NRC regulations identified in

10 CFR 54.4(a)(3) were used to determine system and structure

functions. During system aging management reviews, detailed

component level evaluations were completed to identify components that

are required to support system level functions.

After completion of the system aging management reviews, a database

review was performed that identified safety-related components in the

component database that had not been identified as subject to aging

management review. These components or groups of components were

evaluated to confirm that a suitable basis was used for their exclusion.

See the response to part (a) for discussion of the basis for exclusion of

components classified as safety-related.

The staff concluded that the applicant's response describes the process used during license

renewal scoping activities to disposition components classified as safety related that do not

perform a safety-related intended function and, therefore, adequately addresses the questions

documented in RAI 2.1-3.

10 CFR 54.4(a)(2). Pursuant to 10 CFR 54(a)(2), the applicant must consider to be within the

scope of license renewal all nonsafety-related SSCs whose failure could prevent satisfactory

accomplishment of any of the functions identified in 10 CFR 54(a)(1)(i)-(iii).

The applicant documented the review of scoping activities in support of 10 CFR 54.4(a)(2) in an

engineering report titled, "Aging Management Review of Nonsafety-Related Systems and

Components Affecting Safety-Related Systems." The applicant discussed the scoping

methodology as it relates to the nonsafety-related criteria in accordance with

10 CFR 54.4(a)(2). With respect to the nonsafety-related criteria, the applicant stated that it

performed a review to identify the nonsafety-related SSCs whose failure could prevent

satisfactory accomplishment of the safety-related intended functions identified in 10 CFR

54.4(a)(1).

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As stated in the LRA, the applicant identified nonsafety-related SSCs whose failure could

prevent satisfactory accomplishment of a safety function. It considered the impacts of

nonsafety-related SSC failures as either functional or spatial. In a functional failure, the failure

of an SSC to perform its normal function impacts another safety function. In a spatial failure,

the loss of structural or mechanical integrity 'of an SSC in physical proximity to a safety-related

component impacts a safety function.

The applicant used three steps to evaluate the potential for spatial interaction of fluid-filled,

nonsafety-related piping with safety-related systems or components-(1) determination of

whether the pipe contains liquid, (2) determination of whether the piping system has

components in safety-related structures or a location containing a safety-related system, and

(3) determination of whether the potential exists for spatially related interaction between the

nonsafety-related, fluid-filled system and a safety-related system or component. After

identifying fluid-filled systems through a component database review, the applicant used a

spaces approach to identify nonsafety, fluid-filled systems which are located in the proximity of

safety-related systems.

The applicant installed protective features (e.g., whip restraints, spray shields, supports, and

barriers) to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs.

The applicant included such protective features credited in the plant design within the scope of

license renewal and as subject to an AMR. Where those protective features provide adequate

protection, the applicant excluded the nonsafety-related system itself from the scope of license

renewal. Protective features are typically associated with a structure and are addressed in the

structural AMR.

The audit team determined that the applicant classified SSCs required to perform a function in.

support of other safety-related components as safety-related and included them within the

scope of license renewal. For the few exceptions where nonsafety-related equipment must

remain functional in support of a safety function, the applicant included the supporting systems

within the scope as nonsafety-related SSCs affecting safety-related SSCs. The applicable

sections of the SAR, technical specifications, Maintenance Rule scoping documents, and

design-basis documents provide the system information to determine the appropriate systems

and structures in this category.

For nonsafety-related piping systems directly connected to safety-related SSCs, the nonsafetyrelated piping and supports, up to and including the first equivalent anchor beyond the

safety/nonsafety-related interface, are subject to an AMR. In addition, nonsafety-related

portions of safety-related systems downstream of the first anchor are subject to an AMR if they

have the potential for spatial interaction with safety-related SSCs.

,

By letters dated December 3, 2001, and March 15, 2002, the NRC issued a staff position to the

NEI which describes areas to be considered and options it expects licensees to use to

determine what SSCs meet 10 CFR 54.4(a)(2) (i.e., all nonsafety-related SSCs whose failure

could prevent satisfactory accomplishment of any safety-related functions identified in

10 CFR 54.4(a)(1 )(i-iii)). The December 3 letter provides specific examples of operating

experience which identify pipe failure events (summarized in Information Notice (IN) 2001-09,

"Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the

Containment of a Pressurized Water Reactor") and the approaches the NRC considers

acceptable to determine which piping systems should be included within scope based on

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10 CFR 54.4(a)(2). The March 15 letter further describes the staff's expectations for the

evaluation of nonpiping SSCs to determine which additional nonsafety-related SSCs are within

the scope. The position states that applicants should not consider hypothetical failures, but

rather should base their evaluations on the plant CLB, engineering judgment and analyses, and

relevant operating experience. The paper further describes operating experience as all

documented plant-specific and industry wide experience which can be used to determine the

plausibility of a failure. Documentation would include NRC generic communications and event

reports, plant-specific condition reports, industry reports (e.g., significant operating event

reports), and engineering evaluations.

The audit team determined that Section 2.1.1.2.2, "Spatial Failures of Nonsafety-Related

SSCs," of the LRA states that the nonsafety-related piping and supports, up to and including

the first equivalent anchor beyond the safety/nonsafety interface, are within the scope of license

renewal and subject to an AMR. The staff requested additional information regarding the

process used by the applicant to ensure that it adequately considered all nonsafetycomponents and structures between the safety/nonsafety interface and the first equivalent

anchor point during scoping. Specifically, staff asked the applicant to describe the method

used to ensure that it considered all material-environment combinations between the

safety/nonsafety interface and the first equivalent anchor during an AMR. The staff

documented this as RAI 2.1-4, part (a).

The applicant responded to RAI 2.1-4, part (a), in a letter to the NRC dated May 19, 2004. For

ANO-2, the nonsafety-related piping connected to safety-related piping up to the first equivalent

anchor beyond the safety/nonsafety interface is within the scope of license renewal and subject

to an AMR. The safety/nonsafety interface is normally shown on the LRA drawings through the

use of license renewal boundary flags. In most cases, flags indicate seismic Class 1 evaluation

boundaries on the LRA drawings. However, the exact location of the equivalent anchor may not

be indicated on these drawings. To assure that the LRA AMR summary tables include all

material and environment combinations, the applicant reviewed the systems within the scope of

license renewal that contain safety-related components. The applicant reviewed piping

classifications beyond the license renewal boundary indicated on the drawings for these

systems to ensure that no new material-environment combinations exist. To do this, the

applicant either (1) traced piping from the license renewal boundary back to an obvious anchor

point (i.e., a larger line or a larger component such as a pump or heat exchanger), or (2) when

a seismic Class 1 boundary flag was available, traced the piping back to at least two major

components beyond the flag to identify piping class changes.

This approach assured that the piping reviewed would include the equivalent anchor. If the

applicant identified a piping material or environment change, it compared the change with the

AMR results for that system or a connected system to validate that the material-environment

combination was addressed. The review of these systems confirmed that LRA Section 3.0

includes all applicable material-environment combinations, up to and including the first

equivalent anchor.

The staff concluded that the applicant's response provides information regarding the process it

used to ensure that it adequately considered all nonsafety-components and structures between

the safety/nonsafety interface and the first equivalent anchor point during scoping and

adequately addressed the questions documented in RAI 2.1-4, part (a).

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The audit team determined that Section 2.1.1.2.2 of the LRA states that nonsafety-related

systems and nonsafety-related portions of safety-related systemi`s containing steam or liquid

that are in the proximity of safety-related equipment are considered within the scope of license

renewal, per 10 CFR 54.4(a)(2). However, this section of the LRA also states that long-term

exposure to conditions resulting from a failed nonsafety-related SSC (such as leakage or spray)

is not considered credible. The staff requested that the applicant clarify its position and

methodology relative to the consideration of spray and wetting of safety-related SSCs from the

failure of nonsafety-related equipment. The staff documented this as RAI 2.1-4, part (b).

Specifically, the staff asked the applicant to address the following:

(1) Clarify how it reached the determination that long-term exposure to conditions resulting

from a failed nonsafety-related SSC are not considered credible. Address if the

applicant excluded nonsafety-related SSCs from the scope of license renewal based on

this determination. -

(2) Describe how it considered the effects of short-term wetting and spray on passive and

active safety-related SSCs during 10 CFR 54.4(a)(2) scoping. During the methodology

audit, the applicant indicated that the methodology for evaluating spatial interactions

assumes that safety-related SSCs can withstand short-term duration spray and wetting

without a loss of intended function. Therefore, the staff asked the applicant to clarify its

consideration of the effects of short-term spray and wetting during scoping.

Furthermore, if the applicant assumed that safety-related SSCs could withstand shortterm spray or wetting without a loss of intended function, it should describe the basis for

this assumption.

(3) Identify if it used the System Walkdown Program described in Section B.1.28, uSystem

Walkdown," of the LRA as the sole aging management program (AMP) for any

nonsafety-related structures or components that could potentially spatially interact with

safety-related SSCs. If only the System Walkdown Program manages the effects of

aging for any nonsafety-related SSC, describe the applicant's consideration of the

effects of short-term spray and wetting during scoping and AMR evaluations.

The applicant responded to RAI 2.1-4, part (b), in a letter to the NRC dated May 19, 2004, as

follows:

1. LRA Section 2.1.1.2.2, under the heading of Leakage, Spray, or

Flooding, states that uLong-term exposure to conditions resulting from a

failed nonsafety-related SSC (such as leakage or spray) is not

considered credible." This conclusion was not applied during scoping

evaluations. If a steam or liquid-filled nonsafety-related system (or

nonsafety-related portion of a safety-related system) was in a,

safety-related building, then that system was considered in scope for

10 CFR 54.4(a)(2) regardless of potential exposure duration.. No

nonsafety-related SSCs were excluded from the scope of license renewal

based on the consideration that long-term exposure to conditions

resulting from a failed nonsafety-related SSC was not credible. * ;~~ - - .

2. The potential for wetting or spray on passive and active safety-related

components was considered in scoping evaluations. Nonsafety-related

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-

systems containing steam or liquid that are near safety-related equipment

are considered in scope for 10 CFR 54.4(a)(2) regardless of potential

exposure duration. An assumption that safety-related SSCs could

withstand short-term spray or wetting without loss of intended function

was not applied during scoping or screening.

3. As indicated in Table 3.3.2-11 of the LRA, the System Walkdown

Program is credited as the sole aging management program for some

nonsafety-related components that could spatially interact with

safety-related SSCs. As stated above, the duration of potential spray or

wetting was not a consideration during scoping. The System Walkdown

Program as described in Appendix B.1.28 of the LRA is considered

adequate since it requires periodic walkdowns that will detect and correct

failures caused by long-term exposure to spray or wetting. Short-term

exposure is not a concern for passive components such as valve bodies

and piping. Active safety-related component failures due to short-term

exposure would be detected in the course of normal operation, or through

monitoring required by the maintenance rule, and appropriate corrective

actions would be taken. This is consistent with the Statements of

Considerations for the license renewal rule which states, "On the basis of

consideration of the effectiveness of existing programs which monitor the

performance and condition of systems, structures, and components that

perform active functions, the Commission concludes that structures and

components associated only with active functions can be generically

excluded from a license renewal aging management review. Functional

degradation resulting from the effects of aging on active functions is more

readily determinable, and existing programs and requirements are

expected to directly detect the effects of aging."

The staff concluded that the applicant's response to RAI 2.1-4, part (b), sections 1 and 2,

clarifies its position and methodology relative to the consideration of spray and wetting of

safety-related SSCs from the failure of nonsafety-related equipment and adequately addresses

the questions documented in RAI 2.1-4, part (b), sections 1 and 2. The staff's concern with

respect to using the System Walkdown Program as the sole aging management program for

some nonsafety-related components was resolved by RAI 3.3.3.4.11-1, which is addressed in

Section 3.3 of this SER. Therefore, RAI 2.1-4, part (b), section 3 is resolved.

On the basis of the additional information supplied by the applicant, including the determination

of the credible failures which could impact the ability of safety-related SSCs to perform their

intended functions, evaluation of relevant operating experience, and incorporation of identified

nonsafety-related SSCs into the applicant's AMPs, and the results of NRC inspection and audit

activities, the staff concludes that the applicant has, with the exceptions noted above regarding

the response to RAI 2.1-4, part (b), section 3, supplied sufficient information to demonstrate

that the applicant has identified as within the scope of license renewal all SSCs that meet the

10 CFR 54.4(a)(2) scoping requirements.

10 CFR 54.4(a)(3). Pursuant to 10 CFR 54(a)(3), the applicant must consider all SSCs relied

on in safety analyses or plant evaluations to perform a function that demonstrates compliance

with the Commission's regulations for fire protection (10 CFR 50.48), EQ (10 CFR 50.49), PTS

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(10 CFR 50.61), ATWSs (10 CFR 50.62), and SBO (10 CFR 50.63) to be within the scope of

the license renewal. ANO-2 procedure 02-R-02008-01, "Licenge Renewal Project System and

Structure Scoping Method and Results," details the approach used to identify the scoping of the

SSCs relied upon for these regulated events. The applicant identified SSCs within the scope of

10 CFR 54(a)(3) by reviewing associated plant documents. The NRC audit team reviewed a

sample of the specific documentation referenced in 02-R-02008-01, including the following:

* ANO-2 SAR Section 9.5, "Fire Protection Program"

* ANO Engineering Standard EES-13, "Evaluation of Safe Shutdown Capability"

* ANO-2 Calculation 85-E-0087-01, "Fire Hazard Analysis Report Safe Shutdown-,

Capability Assessment"

* ULD-0-TOP-01, "Environmental Qualification Topical"

* technical specification evaluation A2-EP-2002-004, 'TLAA and Exemption Evaluation"

* ULD-2-SYS-34, Revision 0, "Diverse Scram and Diverse Emergency Feedwater

Actuation Systems" - L '

* ULD-0-TOP-19, Revision 0, "Station Blackout"

As part of its review of the applicant's scoping methodology, the audit team evaluated a sample

of the license renewal database 10 CFR 54(a)(3) scoping results, examined a sample of.the

analyses and documentation to support these reviews, and discussed the methodology and

results with the applicant's personnel responsible for these evaluations.. The team verified that

the applicant had identified and used pertinent engineering and licensing information to

determine the SSCs required to be within scope in accordance with the 10 CFR 54.4(a)(3)-

criteria. Based on this sampling review and discussions with the applicant,- the audit team

determined that the applicant's methodology for identifying systems and structures meeting the

scoping criteria of 10 CFR 54(a)(3) is adequate.

Mechanical Scoping Methodology. The applicant described the methodology used for

mechanical scoping in LRA Section 2.1.1 LRPG-03, and LRPG-04. For each mechanical ,

system within scope of license renewal, the applicant evaluated the components to determine

those subject to an AMR. The applicant reviewed design-basis documents to identify the

specific components that support the intended function of the mechanical system and to

establish evaluation boundaries. -

The applicant determined the evaluation boundary to be that portion of the system that is

necessary to ensure that the intended function of the system will be performed. The applicant

based the evaluation boundary on a review of numerous documents, including the UFSAR,

component database, accident analyses, design-basis documents, and P&lDs. The applicant

marked the evaluation boundary on the system P&ID.

The team determined that the applicant's proceduralized methodology is consistent with the.

description provided in Section 2.1.1 of the LRA and the guidance contained in Section 2.1 of

NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear

2-17
-

Power Plants," (SRP-LR). Based on review of information contained in the LRA, the applicant's

detailed scoping implementation procedures, and a sampling review of mechanical scoping

results, the team concluded that the applicant's methodology for identification of structural

components within the scope of license renewal meets the requirements of 10 CFR 54.4(a).

Structure Scoping Methodology. The applicant described the methodology used for structural

scoping in LRA Section 2.1.1, LRPG-03, and in Section 2.4 of the system scoping method and

results (SAR) procedure 02-R-2008-01, Revision 1. The applicant developed a list of plant

structures from a review of civil/structural and plant layout drawings as the starting point for

scoping and included all structures that could potentially support license renewal. It identified

functions for the structures and structural components and commodities (e.g., pipe supports,

structural steel, foundations, floors, walls, ceilings, penetrations, stairways, and curbs) based on

reviews of plant licensing and design documentation, including the SARs. The applicant relied

upon the SARs to identify safety classification of structures and structural components. The

applicant considered Class I structures and structural components safety related.

The applicant determined structure evaluation boundaries, including examination of structure

interfaces. It evaluated all structure functions against the criteria of 10 CFR 54.4(a)(1-3) and

documented the results of this evaluation in the LRA. In those instances where the structure

intended functions require support from other structures or systems, the applicant identified the

supporting systems or structures and evaluated them against the criteria in 10 CFR 54.4(a)(2).

The applicant used a single boundary diagram based on site plot and equipment layout

drawings, which displays all of the structures in relation to one another. For in-scope

structures, the applicant identified all structural components that are required to support the

intended functions of the structure as within the scope of the Rule.

The audit team reviewed plant drawings and the list of in-scope plant structures that the

applicant developed from a review of civil/structural and plant layout drawings and also

interviewed engineering personnel to further assess the methodology used for scoping. The

audit team compared the applicant's generic structural component listing to the typical structural

commodity groups identified in Table 2.1-5 of the SRP-LR and concluded that the applicant's

general structural component list is reasonable. Following identification of all system

components, the applicant evaluated each component against the scoping criteria of

10 CFR 54.4(a). The applicant classified structural components meeting the criteria of

10 CFR 54.4(a) are within the scope of license renewal.

The audit team determined that the applicant's proceduralized methodology is consistent with

the description provided in Section 2.1.1 of the LRA and the guidance contained in Section 2.1

of the SRP-LR. Based on review of information contained in the LRA, the applicant's detailed

scoping implementation procedures, and a sampling review of structural component and

commodity scoping results, the team concluded that the applicant's methodology for

identification of structural components within the scope of license renewal meets the

requirements of 10 CFR 54.4(a).

Electrical and Instrumentation and Control Scoping Methodology. The applicant described the

methodology used for electrical and l&C scoping in LRA Section 2.1.1, LRPG-03, and

LRPG-05. The applicant used a plant systems list from the ANO-2 component database which

identifies the component safety, safety-related, or Q-classification using the same definition as

that stated in 10 CFR 54.4. Specifically, the ANO-2 definition of safety related, which was used

2-18
to develop and maintain the component-level Q-list, includes the SSCs that are relied on to

remain functional during or following design-basis events. The applicant also used NEI 95-10

to determine the electrical and l&C components to be included within the scope of the license

renewal process for ANO-2.; If any of the'elec'trical components met the criteria of 10 CFR 54.4,

the applicant considered them to be within the'scope of license renewal and documented the

results in Engineering Report 02-R-2008-01, the Scoping Methods and Results Report.;- The

report also describes the method used to identify those electrical systems and structures which

will meet the 10 CFR 54.4 criteria. In additi6n to the plant electrical systems,'the applicant

conservatively included certain nonplant equipment components of the switchyard withiri the

scope of license renewal because of SBO considerations.

2.1.3.2 Screening Methodology

2.1.3.2.1 Mechanical Component Screening

The applicant described the methodology used for mechanical component screening in LRA

Section 2.1.2.1 and LRPG-04.

The applicant determined that components subject to an AMR are those that perform an

intended function without moving parts or a change in configuration or properties (i.e., passive)

and are not subject to replacement based on qualified life or specified time period (i.e., longlived). In accordance with LRPG-04, the applicaent then'determined whether the components

within the evaluation boundary are passive' and long-lived and documented the results.

The NRC audit team reviewed the methodology for identifying mechanical components subject

to an AMR, as well as the applicant's technical justification for this methodology. The team also

examined the applicant's results fromrthe mechanical screening methodology by reviewing 'the

components identified as within the scope of license renewal, the corresponding component'

intended functions, and the resulting list of 66prnonents subject to an AMR.'

The audit team noted that 10 CFR 54.21 (a)(1) requires that SCs subject to an AMR 'encompass

those SCs that (1) perform an intended function without moving parts or a change configuration

or properties and (2) that are not subject to replacement based on a qualified life or'specified

time period. Table 2.173, "Specific Staff Guidance on Screening," of the SRP-LR provides

guidance for determining if consumable items should be subject to an AMR. 'For consumables

that are periodically replaced, Table 2.1-3 states that the applicant should identify the standards

that are relied on for replacement as part of the methodology description. For consumables

such as packing, gaskets, component seals,'arfd 0-rings, Table 2.1-3 states that these

components may be'excluded from an AMR using a clear basis. Section 2.1.2 of the LRA

states that the process for evaluating consumables is'consistent with the NRC staff guidance

on consumables'provided in a letter from C.l Grimes, NRC, to D.J. Walters, NEI, 'dated

March 10, 2000. The staff requested that the applicant provide a more detailed description of

the actual method used to demonstrate th'at it'adequately evaluated the criteria and the basis

for that determination. The staff documented this RAI 2-1.5.

The applicant responded to RAI 2-1.5 in a letter to the NRC dated May 19, 2004. For ANO-2,

the applicant reviewed cons'umable 'subcofiponents based on criteria in'the letter from C.1

Grimes, NRC, to D.J. Walters, NEI, dated March 10, 2000, which is consistent with the SRP2-19
LR, Table 2.1-3, issued April 2001. The applicant provided the following additional detail on the

implementation for ANO-2:

* The applicant excluded packing, gaskets, components seals, and O-rings because

these components are not relied on for the pressure boundary function, as stated in CE

NPSD-1215 and ASME Code, Section 11I.

* The applicant evaluated structural sealants (elastomers) and identified aging effects and

AMPs as applicable.

* Oil, grease, and component filters are tested or inspected periodically and replaced

under ANO-2 maintenance activities. They are excluded because they are considered

short-lived.

* System filters are inspected periodically and replaced as required under ANO-2

maintenance activities. Fire extinguishers and hoses are inspected per ANO-2 SAR

Section 9.5.1 and Appendix 9D. Air packs are maintained under the Self-Contained

Breathing Apparatus Program based on 42 CFR 84, 29 CFR 19.10, 29 CFR 19.26,

NUREG-0041, and ANSI-Z88.2. These items are excluded because they are short-lived

(i.e., periodically inspected and replaced based on their condition).

The staff concluded that the applicant's response provides a more detailed description of the

actual method used to demonstrate that it adequately evaluated the criteria and the basis for

that determination. Therefore, the applicant adequately addressed the questions documented

in RAI 2.1-5.

The team determined that the applicant's mechanical component screening methodology

described in LRA Section 2.1.2.1 is consistent with the guidance contained in the SRP-LR. It is

capable of identifying those passive, long-lived components within the scope of license renewal

that are subject to an AMR. Therefore, the screening methodology for structural components

and commodities is adequate.

2.1.3.2.2 Structural Component Screening

The applicant described the methodology used for structural scoping in LRA Section 2.1.2.2

and LRPG-06. For each structure within the scope of license renewal, the applicant evaluated

the structural components and commodities to determine those subject to an AMR. The

screening process involved a review of design-basis documents to identify specific structural

components and commodities that constitute the structure. The applicant determined that

structural components or commodities subject to an AMR are those that perform an intended

function without moving parts or a change in configuration or properties (i.e., passive) and are

not subject to replacement based on qualified life or specified time period (i.e., long-lived).

Consequently, the applicant determined that since structures are inherently passive, and with

few exceptions long-lived, it based the screening of structural components and commodities

primarily on whether they perform an intended function.

The applicant evaluated structural elements and components in commodity groups based on

materials such as steel, threaded fasteners, and concrete. The scoping and screening

evaluation did not identify and evaluate these multiple structural components on an individual

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basis. Rather, the evaluation grouped similar structural components as generic components for

scoping and screening. The applicant generally' categorized structural components and

commodities that are attached to a structure or reside within a structure as either component

supports or as other structural members.

The applicant established evaluation boundaries'for mechanical component supports in

accordance with ASME Code, Section Xl, Subsection IWF, which governs inspection of

component supports..-For support of electrical components, the evaluation boundary includes

mechanical or integral attachments to the building structure. The evaluation boundary for other

structural members includes the structural component and the associated attachment to the

building structure. The applicant used the guidelines provided in NEI 95-10 to determine the

intended functions of SSCs and commodities for the LRA.

The team reviewed the methodology for identifying structures and structural components and

commodities'subject to an AMR, as well as the applicant's technical justification for this

methodology. The team also examined the applicant's results from the structural screening

methodology by reviewing the structural components and commodities identified as within the

scope of license renewal, the corresponding structural component intended functions, and the

resulting list of structural components subject to an AMR.

Revision 1 to LRPG-06 provides guidance on conducting structural component and commodity

screening. The team reviewed structural component and commodity groups developed under

the screening methodology, which also established evaluation boundaries and intended,

functions. aThe team also reviewed LRA Table 3.5.1, which summarized the AMPs for SC

supports evaluated in NUREG-1 801, "Generic'Aging Lessons Learned (GALL) Report."

The team determined that the applicant's structural component screening methodology

described in LRA Section 2.1.2.2 is consistentrwith the guidance contained in the SRP-LR. It is

-capable of identifying those passive, long-lived components within the scope of license renewal

that are subject to an AMR. Therefore, the screening methodology for structural components

and commodities is adequate.

2.1.3.2.3 Electrical and Instrumentation and Control Component Screening

The applicant described the methodology used for mechanical component screening in LRA

Section 2.1.2.3 and LRPG-04. The applicant separated the active components from the

passive ones using the guidance in NEI 95-10. The screening criteria initially identified passive

electrical systems and components (i.e., those which perform their intended function without

moving parts and without a change in configuration or properties the component are considered

passive). Within the passive components, if the component is not subject to replacement

based on a qualified life or specified time period, it is considered long-lived and subject to an

AMR. As a result, the applicant identified the electrical and l&C system commodities that are

within the scope and subject to AMR in a table in the LRA.

Supports for electrical components include cable trays and conduit supports, electrical panels,

racks, cabinets, and other enclosures. The evaluation boundary for these items includes

supporting elements, such as mechanical or integral attachments to the building structure.

'2-21
a

The team reviewed the methodology for identifying electrical components subject to an AMR,

as well as the applicant's technical justification for this methodology. The team also examined

the applicant's results of the application of the screening methodology by reviewing

components identified as within the scope of license renewal. Procedure LRPG-05 provides

guidance for conducting the electrical screening. The team reviewed the electrical commodity

groups developed under the screening methodology.

The team determined that the applicant's electrical scoping and screening methodology

described in LRA Section 2.1.2.3 is consistent with the guidance contained in the SRP-LR. It is

capable of identifying those passive, long-lived components within the scope of license renewal

that are subject to an AMR. Therefore, the screening methodology for electrical components is

adequate.

The NRC staff's scoping and screening methodology audit identified a number of items

requiring action by the applicant. These are identified in the ANO-2 Audit Trip Report. Most of

the items were resolved thorough request for additional information as noted above. RAI 2.1-4,

part b, section 3 was subsequently resolved and discussed in the resolution of RAI 3.3.3.4.11-1

in Section 3.3 of this SER.

2.1.4 Conclusion

The staff formed the basis of its safety determination based on its review of the information

presented in LRA Section 2.1, the supporting information in LRPG-03, LRPG-04, LRPG-05,

LRPG-06, A2-ME-2003-001 -1, ULD-0-TOP-01, ULD-0-TOP-02, ULD-0-TOP-1 9, ULD-2-SYS34, SAR Section 5.2.4.3.2, ULD-0-TOP-22, LRPG-01, ULD-0-TOP-22, A2-ME-2003-001-1, and

LI-1 10, the information presented during the scoping and screening audit, the NRC scoping and

AMR inspections, and the applicant's responses to the staff's RAls. The staff found that the

applicant's scoping and screening methodology, including its supplemental 10 CFR 54.4(a)(2)

review which brought additional nonsafety-related piping segments and associated components

into the scope of license renewal, is consistent with the requirements of the Rule and the staff's

position on the treatment of nonsafety-related SSCs. On the basis of this review, the staff

concludes that the applicant's methodology for identifying the SSCs within the scope of license

renewal and the SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and

10 CFR 54.21 (a)(1).

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2.2 Plant-Level Scoping Results

In LRA Section 2.2, the applicant provided the results of plant-level scoping review. The staff

reviewed this section of the LRA to determine whether the applicant has properly identified all

plant-level systems and structures that are within the scope of license renewal, as required by

10 CFR 54.4.

2.2.1 Summary of Technical Information In the Application

In LRA Tables 2.2-1a, 2.2-1 b, 2.2-2, 2.2-3, and 2.2-4, the applicant listed plant systems and

structures that are within the scope of license renewal and those that are not within the scope of

license renewal. Based on the design-basis events considered in the plant's CLB, other CLB

information relating to nonsafety-related systems and structures, and certain regulated events,

the applicant identified those plant-level systems and structures within the scope of license

renewal, as defined in 10 CFR 54.4.

2.2.2 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying the SCs that are

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

screening methodology and provides its evaluation in Section 2.1 of this SER. To determine

that the applicant has properly implemented its methodology, the staff focused its review on the

implementation results shown in LRA Tables 2.2-2 and 2.2-4 to confirm that the applicant did

not omit plant-level systems and structures within the scope of license renewal.

The staff considered whether the applicant properly identified the structures and systems within

the scope of license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected

structures and systems identified by the applicant as not falling within the scope of license

renewal to determine that they have no intended functions that do in fact fall within the scope of

license renewal. The staff conducted its review of the applicant's implementation in accordance

with Section 2.2 of the SRP-LR.

The staff reviewed LRA Section 2.2 and sampled the contents of the UFSAR, based on the

listing of systems and structures in LRA Tables 2.2-2 and 2.2-4, to determine whether the

applicant omitted any systems or structures that may have intended functions, as identified by,

10 CFR 54.4, from the scope of license renewal.

During its review of LRA Section 2.2 and LRA Tables 2.2-2 and 2.2-4, the staff determined that

it needed additional information and/or clarification: The following describes the staff's RAI,

provided to the applicant by letter dated May;1 1; 2004, and'the applicant's response.

RAI 2.2-1

The UFSAR does not describe some of the mechanical systems that the applicant determined

not to be within the scope of license renewal, as listed in LRA Table 2.2-2. The staff could not

determine whether these systems have the intended functions that would meet any of the

criteria in 10 CFR 54.4(a)(1-3). For those systems that are not described in the UFSAR, the

staff requested that the applicant briefly describe the system, including its intended function.

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Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that Table 2.2-2 identifies six

mechanical systems that do not have a UFSAR reference. These systems include the

administration building heating and ventilation, diesel fuel services, emergency operations

facility, low-level radwaste, miscellaneous system, and startup boiler.

The administration building heating and ventilation system is a nonsafety-related heating and

air conditioning system that provides ventilation to the administration building. The building

houses offices for site personnel.

The diesel fuel services system includes only two mechanical components, which are

nonsafety-related drain valves for the enclosures around the EDG fuel oil day tanks.

The mechanical components in the emergency operations facility (EOF) include a backup

diesel generator and heating, ventilation, and air conditioning (HVAC) components such as heat

exchangers, blowers, and filters. The EOF serves as an alternate location for the technical

support center and the operational support center, if required by the site emergency plan. The

building is located 1.05 km (0.65 mi) from the reactor buildings and serves as a training center

during normal plant operations.

The mechanical components in the low-level radwaste system include tanks, filters, valves,

compressors, and piping that support various activities in handling low-level radioactive waste in

the low-level radwaste building, which is located outside the plant power block away from

safety-related structures. The low-level radwaste storage building temporarily stores low-level

radioactive waste before its shipment off site. This system is only required to support the

collection and handling of low-level solid radioactive waste.

The miscellaneous system includes miscellaneous site equipment that is entered into the site

component database for work tracking and other purposes but is not a part of an existing

system. The mechanical components include a portable hoist and backup power diesel

generators for site office buildings.

The startup boiler provides auxiliary steam for plant heating and testing as required during

periods when the plant is shut down. The system consists of the boiler, pumps, filters, valves,

piping, and other miscellaneous mechanical components.

Based on its review, the staff finds the applicant's response to RAI 2.2-1 acceptable, because

none of the systems described has an intended function that meets any of the criteria in

10 CFR 54.4(a)(1-3). The staff confirmed that these systems are not within the scope of

license renewal. Therefore, the staff considers its concern described in RAI 2.2-1 resolved.

The staff has completed its review of plant-level scoping results. The staff did not identify any

omissions of structures and systems that meet the scoping criteria of 10 CFR 54.4.

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2.2.3 Conclusion

The staff reviewed LRA Section 2.2, supporting information in the ANO-2 UFSAR, and the.

information provided in the applicant's response to the staff's RAls to determine whether the

applicant omitted any structures and systems that should be within the scope of license

renewal. On the basis of its review, the staff concludes that the applicant has appropriately

identified the structures and systems that are within the scope of license renewal in accordance

with 10 CFR 54.4. Sections 2.3 through 2.5 of this SER provide the staff's detailed review of

the SSCs that are subject to an AMR.

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-- S

2.3 System Scoping and Screening Results-Mechanical Systems

The sections of this SER noted in parentheses address the following mechanical system

scoping and screening results for license renewal:

* reactor coolant system (2.3.1)

- reactor vessel and control element drive mechanism pressure boundary

- reactor vessel internals

- Class 1 piping, valves, and reactor coolant pumps

- pressurizer

- steam generators

* engineered safety features (2.3.2)

- emergency core cooling

- containment spray system

- containment cooling

- containment penetrations

- hydrogen control

* auxiliary systems (2.3.3)

- spent fuel pool

- water suppression fire protection

- emergency diesel generator

- alternate ac diesel generator

- chemical and volume control

- Halon fire protection and reactor coolant pump motor oil leakage collection

- fuel oil

- service water

- auxiliary building ventilation

- control room ventilation

- miscellaneous systems within scope for 10 CFR 54.4(a)(2)

- other miscellaneous systems

* steam and power conversion systems (2.3.4)

- main steam

- main feedwater

- emergency feedwater

Pursuant to 10 CFR 54.21 (a)(1), applicants must identify and list SCs that are subject to an

AMR. These are passive, long-lived SCs that are within the scope of license renewal. To

determine whether the applicant has properly implemented its methodology, the staff focused

its review on the implementation results. This approach allows the staff to confirm that the

applicant has not omitted any system components that are subject to an AMR.

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Staff Evaluation Methodology

The staff's evaluation of the information provided in the LRA was performed in the same

manner for all mechanical systems. The objective of the review was to determine if the

components and -supporting structures for a specific mechanical system that appeared to meet

the scoping criteria specified in the rule were identified by the applicant as within the scope of

license renewal in accordance with 1 0 CFR 54.4. Similarly, the staff evaluated the applicant's

screening results to verify that all long-lived, passive components were subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

Scopina. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of renewal.- The staff reviewed relevant licensing basis

documents, including the UFSAR, for each mechanical system to determine if the applicant had

omitted system components with intended functions delineated under 10 CFR 54.4(a) from the

scope of license renewal. The staff also reviewed the licensing basis documents to determine if

all intended function(s) delineated under 1 0 CFR 54.4(a) were specified in the LRA. If '

omissions were identified, the staff requested additional information to resolve the discrepancy.

Screening. Once the staff's review of the scoping results was completed, the staff evaluated

the applicant's screening results. For those structures and components with intended functions,

the staff sought to determine if the function(s) are performed with moving parts or a change in

configuration or properties, or if they are subject to replacement based on a qualified life or

specified time period, as described in 1 0 CFR 54.21 (a)(1). For those that did not meet either of

these criteria, the staff sought to confirm that these mechanical system components were

subject to an AMR as required by 10 CFR 54.21 (a)(1). If discrepancies were identified,-the

staff requested additional information to resolve them.

In the LRA, the applicant described a methodology-for mechanical system scoping and

screening that interprets 10 CFR 54.21 (a) differently from previous LRAs and the SRP-LR.

Specifically, the applicant did not define the'component-level scoping boundary. For an

in-scope system, the applicant included all components within the scope of license renewal

regardless of their intended functions. The license renewal drawings submitted by the applicant

depict a boundary for the components of a system that are subject to an AMR.. They do not

depict components within the scope of licenre'renewal. On the license renewal drawings, the

applicant highlighted those components that are passive and long-lived and have intended;

functions as subject to an AMR. Therefore,'the LRA Section 2.3 tables do"not identify and list

some components that have intended functions, nor do the license renewal drawings highlight

them, because the component scoping boundary is not defined. The applicant combined

passive, long-lived, and intended function criteria into one screening process to meet the

requirements of 10 CFR 54.21 (a)(1). ' ; .

The methodology used by previous LRA applicants, consistent with the SRP-LR review

guidance, describes two steps to perform scoping and screening. The first step, scoping,

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

The applicant then identified the components of the in-scope system that have intended

functions to be included in the license renewal scope, in accordance with the criteria of

1 0 CFR 54.4(a). The component scoping boundary within a system is then highlighted on

license renewal drawings. The second step, screening, identifies those components in the

'2-27
-a

scoping boundary that are passive and long-lived in accordance with 10 CFR 54.21 (a)(1). The

resulting components from these scoping and screening steps are subject to an AMR.

As a result of using a different scoping and screening process, and with insufficient information

provided in the LRA associated with this methodology, the NRC staff could not determine

whether the applicant omitted any components within the scope of license renewal and subject

to an AMR. The applicant did not provide scoping information at the component-level

equivalent to that provided by previous LRA applicants for the review of systems in LRA Section

2.3.

To better understand the applicant's scoping methodology, the staff visited the ANO-2 plant site

between January 20-22, 2004, to review site documentation including, the applicant's license

renewal project guidelines and procedures. The results of the audit were documented in a trip

report for the site visit issued on May 17, 2004 (ML040610626). The purpose of this plant audit

was to determine, by review of plant information, that system components within the scope of

license renewal were identified and that the components of the in-scope systems subject to an

AMR were properly screened. The staff reviewed the applicant's site documentation in the

following areas:

* license renewal process plan

* license renewal project guidelines-system and structure scoping

* license renewal project guidelines-system screening and AMRs

* engineering report for system and structure scoping method and results

* engineering report for screening results for AMRs

* engineering reports, AMR results for selected systems

* Engineering Report A2-ME-2003-001-1

To ensure that the applicant screened all components of an in-scope system or identified them

as passive and long-lived, in accordance with 10 CFR 54.21(a)(1), the staff audited engineering

reports on the main feedwater system, the emergency feedwater system, and the EDG system.

Additionally, the LRA did not provide sufficient scoping information for the miscellaneous

systems within scope that meet the 10 CFR 54.4(a)(2) criteria. Therefore, the staff reviewed

Engineering Report A2-ME-2003-001-1 to confirm mechanical component scoping and

screening results. As a result of its review of this report, the staff issued RAI 2.3.3.11-3,

described in Section 2.3.3.11 of this SER. The staff also reviewed engineering reports for other

individual systems to confirm the applicant's responses to the staff's draft RAls. A trip report

issued on May 17, 2004 documents the results of the plant audit. In its trip report, the staff

noted which engineering reports it reviewed at the plant site and the additional information that

it requested based on the review of the site documentation.

As a result of the staff's review of LRA Section 2.3 and the plant audit, the staff found that it

needed additional clarification to determine whether the applicant's component-level scoping for

the systems within scope is adequate. Therefore, by letter dated May 11, 2004, the staff issued

RAI 2.3-1, discussed below, to the applicant to determine whether it properly applied the

scoping criteria of 10 CFR 54.4(a).

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RAI 2.3-1

Section 2.1.1 of the LRA states that the applicant prepared license renewal drawings to indicate

components subject to an AMR. However, the license renewal drawing legends indicate that

the highlighted portions of the systems with flags represent the systems and components that

are within the scope of license renewal. The staff noted that this appears to be an

inconsistency between the drawing legend and the LRA statement. The staff requested that

the applicant clarify this discrepancy.

Additionally, 1 0 CFR 54.21 (a)(2) requires applicants to describe and justify the methods used in

complying with 10 CFR 54.21 (a)(1). In LRA Section 2.1.2, the applicant briefly described the

screening methodology, stating, "for each mechanical system within the scope of license

renewal, the screening process identified those components that are subject to an aging

management review." This description of the screening methodology, specifically for.

mechanical systems, is not clear to the staff. It does not adequately describe the method used

to determine how the applicant screened a component from further evaluation. The staff

requested that the applicant clarify the methodology used to perform the screening of

mechanical components and discuss how it established the system evaluation boundaries and

determined the component intended functions.

Applicant's Response and Staff's Evaluation

In its response to the first part of RAI 2.3-1, dated June 10, 2004, the applicant stated that the

LRA Section 2.1.1 statement is correct, and that the drawings are intended to be an aid used in

conjunction with the tables in LRA Section 2.3 to identify and list those SCs subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

In its response to the second part of RAI 2.3-1, dated June 10, 2004, the applicant stated that if

a system is within scope, then all of the components in that system are conservatively :

considered to be within the scope of license renewal for the purpose of identifying SCs that are

subject to an AMR.

The applicant further defined the screening process in accordance with 10 CFR 54.21 (a)(1) for

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

configuration or properties (i.e., passive) and that are not subject to replacement based on a

qualified life or specified time period (i.e., long-lived). The applicant stated that its screening

process identifies functions for the systems based on reviews of applicable plant licensing and'

design documentation. The applicant used sections of the UFSAR, technical specifications,

Maintenance Rule scoping documents, design-basis documents, and ANO topical reports for

the NRC regulations identified in 10 CFR 54.4(a)(1-3) to determine system functions and

identify the components that perform intended functions required to accomplish those system

functions. The applicant stated that the license renewal boundary on the drawings may be.

defined as the evaluation boundary between the portion of the system that performs an

intended function (requires an AMR) and the portion of the system that does not perform an

intended function (does not require an AMR).-

Based on its review of the applicant's response and discussions with the applicant in a

subsequent teleconference, the staff requested further information on the process of screening

of mechanical components and the identification of the evaluation boundary.

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- --

In its clarification letter dated July 22, 2004, the applicant stated that the identification of

components subject to an AMR began with determining the system evaluation boundary. The

evaluation boundary includes those portions of the system necessary to ensure that the

intended functions of the system will be performed. The applicant included components

needed to support system-level intended functions identified in the scoping process within the

evaluation boundary. System components that do not support an intended function are outside

the evaluation boundary and were not considered further.

The applicant also stated that, within the evaluation boundary, screening was performed to

determine components that are subject to an AMR. Each component subject to an AMR was

assigned a component intended function, such as pressure boundary or heat transfer, that

supports the system intended function. It grouped individual components where possible to

allow disposition of the entire group with a single AMR. The applicant grouped components

based on common materials of construction and common environments, then identified the

aging effects requiring management for each component group. These component groups are

the component types identified in the LRA Section 3.x.2-y tables, where 3 indicates the

application section number; x indicates the table number from Volume 1 of the GALL Report; 2

indicates that this is the second table in the section; and y indicates the system table number.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3-1 acceptable because it adequately describes the scoping and

screening methodology for mechanical components and the definition of the evaluation

boundary, and because it provides confirmation that the applicant did not omit any mechanical

components from the scope of license renewal. Therefore, the staff considers its concern

described in RAI 2.3-1 resolved.

On the basis of its review of the results of the plant audit, the LRA, and the applicant's

responses to RAls, the staff finds that the applicant's methodology for scoping and screening is

well documented in an auditable and retrievable form at the plant site. The staff finds that the

results of the audit on the three selected systems confirm that the applicant did not omit any

components subject to an AMR for these systems. In the LRA Section 2.3 tables, the staff

finds that the results are consistent with the methodology and are acceptable. With the

additional information obtained from the site, the staff concludes that the applicant, while using

a different methodology from that described in the review guidance of the SRP-LR, provided

scoping and screening results and components subject to an AMR with no omissions.

For other in-scope systems that the staff did not audit at the plant site, The staff issued RAIs

related to components that could be subject to an AMR based on its review of the LRA,

UFSAR, and site documentation. The following describes the staff's detailed review of the

balance of plant systems in LRA Section 2.3.

2.3.1 Reactor Coolant System

In Section 2.3.1 of the LRA, the applicant identified the SCs of the RCS that are subject to an

AMR for license renewal. The applicant described the RCS in the following sections of the

LRA:

* reactor vessel and control element drive mechanism pressure boundary (2.3.1.1)

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. . -

* reactor vessel internals (2.3.1.2)

* Class 1 piping, valves, and reactor coolant pumps (2.3.1.3)

* pressurizer (2.3.1.4)

* steam generators (2.3.1.5)

The applicant identified the following criteria for the RCS to determine the SSCs that are within

the scope of license renewal: < ..

* safety-related 10CFR

54.4(a)(1)

* nonsafety-related that can prevent a safety-related function 10 CFR 54.4(a)(2)

* pressurized thermal shock 10 CFR 54.4(a)(3)

* station blackout , 10 CFR 54.4(a)(3)

* anticipated transient without scram 10 CFR 54.4(a)(3)

* environmental qualification 10 CFR 54.4(a)(3).

* fire protection - ; 10 CFR 54.4(a)(3)

2.3.1.1 Reactor Vessel and Control Element Drive Mechanism Pressure Boundary

2.3.1.1.1 Summary of Technical Information in the Application

In Section 2.3.1.1 of the LRA, the applicant described the reactor vessel and control element

drive mechanism (CEDM) pressure boundary. The ANO-2 reactor vessel and CEDM pressure

boundary items subject to an AMR include the closure head; closure head flange; closure stud

assemblies; vessel flange; upper, intermediate, and lower shells; core stabilizing and stop lugs;

core barrel support ledge; vessel supports; bottom head; primary coolant nozzles and safe

ends; pressure boundary subcomponents of the CEDMs; CEDM, nozzles; instrumentation

nozzles; surveillance capsule holders; flow'skirt; and vent line. The vessel contains the nuclear

fuel core, core support structures, control rods, and other parts directly associated with the

core.

Two hollow metallic O-rings seal the reactor vessel closure. Two leak-off connections, one

between the inner and outer ring and one outside the outer O-ring, detect seal leakage. The 0-

rings do not support an intended function of the reactor vessel and are therefore not subject to

anAMR.

In Table 2.3.1-1 of the LRA, the applicant identified the reactor vessel and CEDM pressure

boundary component types that are within'the scope of license renewal and subject to an AMR,

including closure head lifting lugs, closure studs, closure nuts and washers, core stabilizing

lugs, core stop lugs, flow skirt, grayloc clamp, grayloc clamp studs, grayloc clamp nuts, in-core

instrumentation (ICI) drive nuts, ICI spacer sleeves, reactor vessel support pads, shear lugs,

surveillance capsule holders, CEDM motor housing, CEDM upper pressure housing, CEDM ball

seal housing, CEDM upper pressure housing upper fitting, CEDM motor housing upper and ,

lower end fittings, CEDM upper pressure housing lower fitting, CEDM nozzle, ICI nozzle tubes,

CEDM steel ball, ICI flange adapter/seal plate, reactor vessel vent pipe, reactor vessel vent

pipe flange, bottom head (torus and dome), upper shell, closure head dome (torus and dome),

closure head flange, intermediate shell; lower shell, primary inlet nozzles, primary outlet -

nozzles, primary inlet nozzle safe ends, primary outlet nozzle safe ends, and vessel flange.

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2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1, Table 2.3.1-1, and SAR Sections 4.2.3 and 5.4.6 to

determine whether the applicant identified the reactor vessel and CEDM pressure boundary as

within the scope of license renewal and subject to AMR, in accordance with the requirements of

10 CFR 54.4 and 1 0 CFR 54.21 (a). The staff used the evaluation methodology described in

Section 2.3 of this SER. The staff conducted its review in accordance with the guidance described

in Section 2.3, "Scoping and Screening Results-Mechanical Systems," of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any reactor vessel components

with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the reactor

vessel components that the applicant identified as within the scope of license renewal

to determine that the applicant did not omit any passive and long-lived components that should

be subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.1.1, the staff identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter to the applicant dated April 23, 2004, the staff issued an RAI concerning the

exclusion of the reactor vessel O-rings leak monitor tube to determine whether the

applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria

of 10 CFR 54.21(a)(1).

The staff asked the applicant to confirm whether the O-ring leak monitor tube serves as a

pressure boundary and whether the piping should be within the scope of license renewal. In its

response, dated May 24, 2004, the applicant stated that the reactor vessel flange leak detection

piping contains an integral orifice with the flange itself which limits flow (in the event of O-ring

failure) to within the makeup capability of the plant. In the event of leakage past the O-rings

and through the restricting orifice, the downstream vessel leak detection piping and associated

valves do not perform an RCS pressure boundary function and would only serve to direct RCS

fluid to the drain tank. The staff finds the response acceptable.

On the basis of its review, the staff found that the applicant has identified those portions of the

RCS that meet the scoping requirements of 1 0 CFR 54.4(a) and has included those portions of

the system within the scope of license renewal in LRA Section 2.3.1.1. The applicant has also

included RCS components that are subject to an AMR in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff did not identify any omissions.

2.3.1.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings,

and licensing basis information, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the reactor vessel and RCS CEDM pressure

boundary. Therefore, the staff concludes that the applicant has adequately identified the RCS

SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the reactor vessel system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.1.2 Reactor Vessel Intemals

2.3.1.2.1 Summary of Technical Information in the Application

In Section 2.3.1.2 of the LRA, the applicant described the reactor vessel internals. The reactor

vessel internals are designed to support and orient the reactor core and control element

assemblies, direct the reactor coolant flow from the core, and guide the IC0. The reactor vessel

internals subject to an AMR include the upper internals assembly, control element assembly

(CEA) shroud assemblies, core support barrel (CSB) assembly, core-shroud assembly, lower

internals assembly, and ICI.

In Table 2.3.1-2 of the LRA, the applicant listed the reactor vessel internals component types

that are within the scope of license renewal and subject to an AMR, including CEA instrument.

tube, CEA shroud adapter, CEA shroud support,' positioning plate, CEA shroud extension shaft

guides,'shaft cylinders, shaft bases, CEA shroud base, CEA shroud flow channel, CEA shroud

flow channel cap, CEA shroud shaft retention pin,' CEA shroud retention block, external spanner

nut, internal spanner nut, CEA shroud fasteners, CEA'shroud flow channel extension, CEA

shroud tube, core shroud plates, plates, ribs, intermediate plates, core shroud guide lugs, CSB

alignment keys; CSB assembly dowel pin, CSB lifting bolt insert, CSB lower flange, CSB lug,,

CSB nozzle, CSB cylinder, CSB upper flange, guide tubes, ICI thimble support plate assembly,

ICI support plate, grid, lifting support, lifting plate, column, plates, funnel, pad, ring, nipple, hex

bolt, spacer, threaded rod, hex jam nut, thimble support nut, cap screws, bottom plate, bottom

plate manhole cover, and cylinder.

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2, Table 2.3.1-2, and SAR Section 4.2.2 to determine

whether the applicant identified the reactor vessel internals within the scope of license renewal

and subject to AMR, in accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a).

The staff used the evaluation methodology described in Section 2.3 of this SER. The staff

conducted its review in accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of:10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any reactor vessel components

with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the reactor

vessel components that the applicant identified as within the scope of license renewal to

determine that the applicant did not omit any passive and long-lived components that should be

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

In reviewing LRA Section 2.3.1.2, Table 2.3.1.2-2, the staff identified an area in which it needed

additional information to complete the evaluation of-the applicant's scoping and screening

results. Therefore, by letter to the applicant dated April 23, 2004, the staff issued an RAI

concerning the exclusion of the CSB snubber bolts to determine whether the applicant

has properly applied the scoping criteria'of 10 CFR 54.4 (a) and the screening criteria of

10 CFR 54.21 (a)(1).

Based on its position that the CSB snubber bolts serve as a pressure boundary and the bolts

should be within the scope of license renewal, the staff requested justification for the exclusion

2-33
of the component. In its response dated May 24, 2004, the applicant stated that it inadvertently

omitted the CSB snubber bolts from the LRA but will include them in the LRA. The staff finds

this acceptable.

On the basis of its review, the staff found that the applicant has identified those portions of the

RCS that meet the scoping requirements of 10 CFR 54.4(a) and has included those portions of

the system within the scope of license renewal in LRA Section 2.3.1.1. The applicant has also

included RCS components that are subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff identified one omission.

2.3.1.2.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings,

and licensing basis information, the staff identified the omission of CSB snubber bolts.

Subsequently, the applicant included the CSB snubber bolts in the scoping and screening

results for reactor vessel components. The staff determined that this error was not indicative of

a flawed scoping and screening methodology. Therefore, the staff concludes that the applicant

has adequately identified the reactor coolant components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the RCS SCs that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.1.3 Class 1 Piping, Valves, and Reactor Coolant Pumps

2.3.1.3.1 Summary of Technical Information in the Application

In Section 2.3.1.3 of the LRA, the applicant described Class 1 piping, valves, and reactor

coolant pumps (RCPs). The following RCS Class 1 piping and associated pressure boundary

components are subject to an AMR:

* hot- and cold-leg straight sections and elbows

* surge line straight sections and elbows

* spray line, safety injection, pressurizer safety/relief, and letdown piping straight sections

and elbows

* vent, drain, and sampling piping straight sections and elbows

* reactor vessel leak detection lines

* charging, letdown, and drain nozzles

* safety injection nozzles

* resistance temperature detector (RTD), replacement pressure nozzles, and pressure

measurement and sampling nozzles

* nozzle thermal sleeves

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* nozzle safe ends and inserts

* safety injection and charging nozzle thermal sleeves

* welds

* -flow orifices

* reactor coolant pumps

* valves

Certain Class 1 valve subcomponents are not subject to an AMR because they are not passive

components (i.e., performance of their intended functions requires moving parts or a change in

configuration). These include the valve disks, stems, yokes, and operators. Pressure-retaining

portions of Class 1 valves consist of the valve body bonnet and closure bolting.

The principle pressure boundary subcomponents of the RCPs include the casing, cover/thermal

barrier, driver mount assembly, heat exchanger, seal cartridge, and studs/nuts. Although'the'

pump seal cartridges are part of the pressure boundary and are within the scope of license

renewal, an AMR is not required since the seal cartridges are periodically monitored, inspected,

and replaced. The remaining RCP subcomponents are not subject to an AMR since they do

not perform their intended functions without moving parts. These items include the impeller,

shaft and journal, radial bearing, and coupling.

This section includes small portions of RCS instrumentation and sampling tubing, such as

reactor coolant pressure boundary items (valves and tubing) downstream of instrument root

valves.

In Table 2.3.1-3 of the LRA, the applicant listed the Class 1 piping, valve, and RCP component

types that are within the scope of license renewal and subject to an AMR, including charging

inlet nozzle, safety injection nozzle, surge line nozzle, charging inlet nozzle safe end, drain

nozzle safe ends, letdown nozzle safe ends, pressure measurement nozzle safe end, sampling

nozzle safe end, charging inlet nozzle thermal sleeve, safety injection nozzle thermal sleeve,

surge line thermal sleeve, Class 1 boundary orifices, Class 1 pipe and fittings (nominal pipe

size (NPS) less than 4"); Class 1 pipe (NPS less than 4"), Class 1 fittings, cold-leg piping and

elbows, hot-leg piping and elbows, drain nozzles, letdown nozzles, shutdown cooling outlet

nozzle, spray nozzle, pressure measurement nozzle, replacement pressure nozzle, sampling

nozzle, RCP safe ends, RTD nozzles, safety injection nozzle safe end; shutdown cooling outlet

nozzle safe end, surge nozzle safe'end, stainless steel bolting, surge line pipe and elbows,

surge line piping RTD nozzles and sampling nozzles, carbon/alloy steel bolting, valve bodies

and bonnets, Class 2 and 3 closure bolting,'Class 2 and 3 fittings, Class 2 and 3 pipe, Class 2

and 3 valve bodies and bonnets, tubing, RCP, RCP casing, RCP cover, RCP cover studs, RCP

cover nuts, RCP driver mount assembly, RCP thermal barrier heat exchanger inner coil, RCP

thermal barrier heat exchanger, outer coil, and RCP thermal barrier bored hole heat exchanger.

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- Z

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3, Table 2.3.1-3, and SAR Sections 5.5.3, 5.5.12, and

5.5.13 to determine whether the applicant identified the Class 1 piping, valves, and RCPs within

the scope of license renewal and subject to AMR, in accordance with the requirements of

10 CFR 54.4 and 10 CFR 54.21 (a). The staff used the evaluation methodology described in

Section 2.3 of this SER. The staff conducted its review in accordance with the guidance described

in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any Class 1 piping, valves, and

RCP components with intended functions delineated under 10 CFR 54.4(a). The staff then

reviewed the RCS components that the applicant identified as within the scope of license

renewal to determine that the applicant did not omit any passive and long-lived components that

should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). The

staff did not identify any omissions.

2.3.1.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for Class 1 piping, valves, and RCPs. Therefore, the

staff concludes that the applicant has adequately identified the reactor vessel components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel

system SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.4 Pressurizer

2.3.1.4.1 Summary of Technical Information in the Application

In Section 2.3.1.4 of the LRA, the applicant described the pressurizer. The pressurizer

pressure boundary items include the vessel, attached nozzles, and safe ends out to the

connection with RCS piping. Section 2.3.1.3 discusses valves (i.e., safety and relief),

instrument lines, and other piping connected to the pressurizer. The following pressurizer

subcomponents support the RCS pressure boundary and are subject to an AMR:

* upper and lower shell, upper head

* lower head (including internal integral attachment for heater support plates)

* manway assembly (including cover plate, gasket retainer plate, studs, and nuts)

* pressurizer surge, spray, and safety/relief nozzles and safe ends

* temperature, pressure, level nozzles, and safe ends

* nozzle inserts, flanges, and thermal sleeves

* heater sheath, sleeve, and end plug

* heater support plates and bolting

* heater penetration plugs

* pressurizer support skirt

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The following pressurizer subcomponents are not subject to an AMR since they do not support

an intended function of the pressurizer, do not perform intended functions without moving parts

or a change in configuration, or are considered consumable items:

* spray head reducer assembly, bolting,- nozzle, and hex nut

* - gaskets (spray nozzle, mechanical nozzle seal assemblies)

* -surge nozzle screen assemblies

* heater elements

In 2002, the applicant repaired six pressurizer heater sleeves using mechanical nozzle seal

assemblies (MNSAs). These assemblies replace the function of the partial penetration Jgroove welds that attach the heater sleeves to the pressurizer, moving the reactor coolant

pressure boundary to the pressurizer exterior surface. The MNSAs consist of two splitsealflange assemblies placed in a counter-bore around the leaking heater sleeve. The seal is

held under compression by a compression collar, which is held in place by threaded rods

placed into holes drilled and tapped into the bottom head of the pressurizer. The MNSA items

subject to an AMR include the compression collar, the upper flanges, and the bolting (threaded

rods, nuts, and washers).

The intended function of the pressurizer components is to maintain the pressure boundary so

that the RCS may perform its system functions for the period of extended operation. However,

the pressurizer components also have a second intended function of RCS pressure control.

The pressurizer components provide RCS pressure control for mitigation of a feedwater line

break with ac available, as described in SAR Section 15.1.14.2.2.2. However, the most limiting

feedwater line break is without ac power available, and the pressurizer sprays are not credited

to mitigate that event. Therefore, RCS pressure control using the pressurizer sprays is not an

intended function of the pressurizer. Pressurizer heaters are required to maintain subcooling

following the loss of offsite power, as described in SAR Section 5.5.10.2. However, the

electrical heater elements are active and not subject to an AMR.

In Table 2.3.1-4 of the LRA, the applicant listed the pressurizer component types that are within

the scope of license renewal and subject to an AMR, including heater end plug, heater sheaths,

heater sleeves, heater support channel, heater support plates, heater support plate brackets,

heater support plate bracket bolts, lower head, lower shell, upper shell, upper head, lower level

nozzle, manway cover bolts/studs, manway cover plate, manway forging, manway gasket

retainer plate, MNSA bolting (studs, nuts, and washers), MNSA compression collar, MNSA

upper flanges, pressure measurement nozzle,,upper level nozzle, vent nozzle, temperature

nozzle, pressure measurement nozzle safe end, upper/lower level nozzle safe end, temperature

nozzle safe end, vent nozzle safe end,- safety valve nozzle, spray nozzle, surge nozzle, safety

valve nozzle flange, spray nozzle safe end,-spray nozzle thermal sleeve, surge nozzle thermal

sleeve, support skirt, and surge nozzle safe end.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4, Table 2.3.1-4, and SAR Section 5.5.10 to determine

whether the applicant identified the pressurizer, associated components, and supporting

structures within the scope of license renewal and subject to AMR, in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21 (a). The staff used the evaluation

- 2-37
methodology described in Section 2.3 of this SER. The staff conducted its review in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any pressurizer components with

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the pressurizer

components that the applicant identified as within the scope of license renewal to determine

that the applicant did not omit any passive and long-lived components that should be subject to

an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). In reviewing LRA Section

2.3.1.1, the staff identified an area in which it needed additional information to complete the

evaluation of the applicant's scoping and screening results. Therefore, by letter to the applicant

dated April 23, 2004, the staff issued an RAI concerning the use of pressurizer sprays to

determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4 (a)

and the screening criteria of 10 CFR 54.21(a)(1).

The staff asked the applicant to clarify whether it took credit for the sprays in the accident

analysis. In its response, dated May 24, 2004, the applicant stated that it assumed pressurizer

spray to function in order to establish the worst conditions for the analysis, but it did not credit

the spray in the feedwater line break analysis or include it within the scope of LRA. The staff

finds this acceptable.

The applicant confirmed in a letter dated May 27, 2004, that the pressurizer relief valve

discharge piping and quench tank are within the scope and are identified in LRA Table 2.3.3-11

as 'piping" and "tank," as required by 10 CFR 54.4(a)(2). The staff finds this acceptable.

On the basis of its review, the staff found that the applicant has identified those portions of the

pressurizer that meet the scoping requirements of 10 CFR 54.4(a) and has included those

portions of the system within the scope of license renewal in LRA Section 2.3.1.1. The

applicant has also included pressurizer system components that are subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). The staff did not

identify any omissions.

2.3.1.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omission or discrepancies in the

applicant's scoping and screening results for the pressurizer. Therefore, the staff concludes

that the applicant has adequately identified the pressurizer system SCs that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the pressurizer system SCs that

are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.5 Steam Generators

2.3.1.5.1 Summary of Technical Information in the Application

In Section 2.3.1.5 of the LRA, the applicant described the steam generators. The following

ANO-2 steam generator components are subject to an AMR:

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I
* tube plate

* U-tubes

* channel head

* channel hMad divider plate

* primary manway cover and insert plate

* primary nozzles, safe ends, and closure rings

* bolting

* tube support plates

* wrapper

* -antivibration bars, bar end caps, and end cap welds

* U-bend peripheral retaining rings, retainer bars, retainer bar welds

* feedwater and steam outlet nozzle

* upper and lower shell barrels, elliptical heads, and transition cones

* feedwater thermal sleeves

* secondary manway covers

* -hand hole covers

* inspection port covers and diaphragms

* blowdown and sampling nozzles

* instrument taps

* stay rods, spacer pipes, and hex nuts

* integral flow restrictors (venturis)

* snubber lugs and key brackets i

* tube plugs

The following steam generator components are not subject to an AMR since they do not

support an intended function of the steam generator or are considered consumable items:

* gaskets

* primary and secondary moisture separation equipment and associated supports and

decking

* sludge collector assembly

* feedwater distribution ring pipe and fittings

The steam generator intended functions which form the basis for inclusion into the scope of

license renewal include maintenance of the primary pressure boundary,,maintenance of the

secondary pressure boundary, heat transfer.from the primary fluid to the secondary fluid, and

flow control. ;

In Table 2.3.1-5 of the LRA, the applicant listed the steam generator component types that are

within the scope of license renewal and subject to an AMR, including channel head, primary

inlet nozzle, primary nozzle safe ends, primary outlet nozzle, channel head divider plate,

primary bolting (studs, closure nuts and washers, and screws), primary manway cover, primary

manway insert plate, primary nozzle closure rings, tube plate, tube plugs, U-tubes, 3" inspection

port cover, 3" inspection port diaphragms, 6" inspection port cover, 8" hand hole cover,

antivibration bars, tube support plates, antivibration bar end caps, peripheral retaining rings, Ubend, U-shaped retainer bars, blowdown and sampling nozzles, narrow- and wide-range water-

'2-39
- - s

level taps, elliptical head, transition cone, upper and lower shell barrels, feedwater inlet nozzles,

feedwater thermal sleeve, flow limiting insert (integral flow restrictors (venturis)), key bracket,

snubber lug, secondary bolting (studs, closure washers, and nuts), secondary manway cover,

steam outlet nozzle, tube bundle support system (stay rods, stay rod hex nuts, spacer pipes,

and peripheral backup bars), wrapper, and wrapper jacking screws.

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.5, Table 2.3.1-5, and SAR Section 5.5.10 to determine

whether the applicant identified the steam generator, associated components, and supporting

structures within the scope of license renewal and subject to AMR, in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21(a). The staff used the evaluation methodology

described in Section 2.3 of this SER. The staff conducted its review in accordance with the

guidance described in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any steam generator components

with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the steam

generator components that the applicant identified as within the scope of license renewal to

determine that the applicant did not omit any passive and long-lived components that should be

subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). In reviewing

LRA Section 2.3.1.1, the staff identified an area in which it needed additional information to

complete the evaluation of the applicant's scoping and screening results. Therefore, by letter to

the applicant dated April 23, 2004, the staff issued an RAI concerning the internal feedwater

distribution ring and the thermal sleeve connecting the header and the nozzle to determine

whether the applicant has properly applied the scooping criteria of 10 CFR 54.4 (a) and the

screening criteria of 10 CFR 54.21(a)(1).

The staff requested the licensee to provide the bases for the exclusion of feedwater distribution

ring and the thermal sleeve from the scope of license renewal. In its response dated May 25,

2004, the applicant stated that the internal feedwater distribution ring and the thermal sleeve

connecting the header and the nozzle do not perform the pressure boundary function of the

steam generators. The staff finds this acceptable.

On the basis of its review, the staff found that the applicant has identified those portions of the

steam generator that meet the scooping requirements of 10 CFR 54.4(a) and has included

those portions of the system within the scope of license renewal in LRA Section 2.3.1.1. The

applicant has also included steam generator components that are subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff did not

identify any omissions.

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2.3.1.5.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scooping and screening results for the steam generator. Therefore, the staff

concludes that the applicant has adequately identified the steam generator components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel

system SCs that are subject to an AMR,-as required by 10 CFR 54.21 (a)(1).

2.3.2 Engineered Safety Features Systems.-.

In Section 2.3.2 of the LRA, the applicant identified the SCs of the engineered safety features

that are subject to an AMR for license renewal. Chapter 6 of the SAR describes the engineered

safety features. This section includes the following systems:

* emergency core cooling -

* containment spray system

* containment cooling

* containment penetrations

* hydrogen control

2.3.2.1 Emergency Core Cooling

2.3.2.1.1 Summary of Technical Information in the Application

In Section 2.3.2.1 of the LRA, the applicant described the emergency core cooling system

(ECCS). The ECCS provides core cooling and core reactivity control under accident conditions,

including a loss-of-coolant accident (LOCA) or a main steamline break. Following a LOCA, the

cooling must prevent fuel melting or significant alteration of core geometry, limit the cladding

metal-water reaction, and remove the energy generated in the core for an extended period of

time. In the unlikely.event of a main steamline break, the ECCS injects borated water into the

RCS to prevent fuel damage and to increase the shutdown margin of the core.

The major ECCS subsystems are the high.pressure safety injection (HPSI), low-pressure safety

injection (LPSI), and safety injection tanks: The LPSI system consists of two pumps that

discharge into a combined low-pressure header that has a return connection from the shutdown

cooling heat exchangers. The HPSI system has three electric motor-driven pumps installed in

parallel. Two high-pressure injection headers and eight motor-operated injection valves

connect the pumps to the four injection points on the RCS loop cold legs. The LPSI and HPSI

pumps are designed to take suction initially from the refueling water tank (RWT) and inject

water into the RCS to provide core cooling. Injection piping and valves connect the safety

injection tanks, containing borated water pressurized with nitrogen, to the RCS.

Section 2.3.1 of this SER evaluates the Class 1 components of the ECCS with the RCS.

Section 2.3.3.5 of this SER evaluates certain components classified with the HPSI system,

which are part of the chemical and volume control system (CVCS) charging lines at the

interface with the injection headers. The LPSI system contains nonsafety-related components

whose failure could impact safety-related components. Therefore, the ECCS is within the

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scope of license renewal based on the criteria of 10 CFR 54.4(a)(2). Section 2.3.3.11 of this

SER evaluates these components.

The ECCS evaluation includes the CVCS valve in the supply from the RWT and primary

sampling system components associated with ECCS.

The LPSI pumps, shutdown cooling heat exchangers, and associated equipment in the flow

path are credited with RCS decay heat removal for safe shutdown after a fire. The UB" HPSI

pump and injection valves in the HPSI system are credited with reactor coolant inventory

maintenance for safe shutdown after a fire. These components perform functions that

demonstrate compliance with the Commission's regulations for fire protection (1 0 CFR 50.48).

The ECCS is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1-3).

In Table 2.3.2-1 of the LRA, the applicant listed the ECCS component types that are within the

scope of license renewal and subject to an AMR, including bearing housing, bolting, heat

exchanger (shell), heat exchanger (tubes), nozzle, orifice, piping, pump casing, tank,

thermowell, tubing, and valves.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1, Table 2.3.2-1, and SAR Section 6.3 to determine

whether the applicant identified the ECCS subsystems (e.g., piping, tanks, and pump casing)

and supporting structures that are within the scope of license renewal and subject to AMR, in

accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a). The staff used the

evaluation methodology described in Section 2.3 of this SER. The staff conducted its review in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any ECCS components with

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the ECCS

components that the applicant identified as within the scope of license renewal to determine

that the applicant did not omit any passive and long-lived components that should be subject to

an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). The staff did not identify

any omissions.

2.3.2.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scooping and screening results for ECCS. Therefore, the staff concludes that the

applicant has adequately identified the reactor vessel components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the reactor vessel system SCs that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.2.2 Containment Spray System

2.3.2.2.1 Summary of Technical Information in the Application

In Section 2.3.2.2 of the LRA, the applicant described the containment spray system. The

containment spray system provides spray cooling water to the containment atmosphere,

following a LOCA or main steamline break inside containment. This cooling water limits the

peak pressure in containment to below containment design pressure. The containment spray

system also removes radioactive iodine from the containment atmosphere during a LOCA.

The containment spray system consists of two independent flow trains. Each train includes a

pump, heat exchanger, and sets of spray nozzles and ring headers, with associated piping, -

valves, and instrumentation necessary for operation. The RWT provides the source of borated

water to the containment spray system during the injection phase of an accident. Once the

RWT is exhausted, the containment spray system takes suction from the water accumulated in

the containment recirculation sump.

The RWT, which is included in the containment spray system boundary, provides a source of

borated water for the ECCS and the containment spray system during postaccident operations.

The containment sump header mechanical components are reviewed with the containment

spray system. This system includes the shutdown cooling heat exchangers since they cool the

spray water under accident conditions.

This system contains nonsafety-related components whose failure could impact safety-related

components. Section 2.3.3.11 of this SER evaluates these components.

Portions of the containment spray system, such as the RWT and the components necessary for

shutdown cooling operation, are required for compliance with the Commission's regulations for

fire protection (10 CFR 50.48). The containment spray system is within the scope of license

renewal based on the criteria of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3).

In Table 2.3.2-2 of the LRA, the applicant listed the containment spray system component types

that are within the scope of license renewal and subject to an AMR, including bolting, filter

housing, heat exchanger (shell), heat exchanger (tubes), heat exchanger (tubesheet), heater

housing, nozzle, orifice, piping, pump casing, tank, thermowell, tubing, valves, and vortex

breaker.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.2 and 2.3.3.11 and ANO-2 UFSAR Section 6.2.2 using

the evaluation methodology described in Section 2.1 of this SER. The staff conducted its

review in accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff reviewed the system functions described in the LRA and the

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any components with intended

functions delineated under .10 CFR 54.4(a). -The staff then reviewed those that the applicant

identified as within the scope of license renewal to determine that the applicant did not omit any

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passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21(a)(1).

The staff found that the applicant included those portions of the containment spray system that

meet the scoping requirements of 10 CFR 54.4 within the scope of license renewal and

identified them as such in LRA Section 2.3.2.2. The staff also found that LRA Table 2.3.2-2

includes the containment spray system components that are subject to an AMR, in accordance

with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). The staff did not identify any omissions.

2.3.2.2.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and licensing

basis information, the staff did not identify any omissions or discrepancies in the applicant's

scoping and screening results for the SCs of the containment spray system. Therefore, the

staff concludes that the applicant has adequately identified the containment spray system SCs

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the

containment spray system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.3 Containment Cooling

2.3.2.3.1 Summary of Technical Information in the Application

In Section 2.3.2.3 of the LRA, the applicant described the containment cooling system (CCS).

The CCS provides cooling and air circulation inside containment. It reduces the containment

pressure and temperature after a postulated LOCA or main steamline break by removing

thermal energy from the containment atmosphere. This also lowers offsite radiation levels by

minimizing the pressure differential between the containment atmosphere and the outside

atmosphere, thereby reducing the driving force for leakage of fission products from

containment.

The CCS is an AMR system (see Section 2.2 of this SER) that includes system codes reactor

building heating and ventilation (RBHV) and reactor building purge air. Section 2.3.2.5 of this

SER evaluates the hydrogen recombiners with the hydrogen control system.

The RBHV system provides cooling and heating to containment during power operation, plant

shutdown, and accident conditions. The RBHV system consists of the containment cooling

units (including fans, chilled water cooling coils, and service water cooling coils), the

containment recirculation fans (which are evaluated with the hydrogen control system in Section

2.3.2.5 of this SER), nonsafety-related CEDM shroud cooling units, and nonsafety-related

reactor cavity cooling fans. The RBHV system contains safety-related components and is

therefore within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1). This

system contains nonsafety-related components whose failure could impact safety-related

components and is therefore within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(2). Section 2.3.3.11 evaluates these components.

The reactor building purge air system provides outside air to purge the containment building

during plant shutdown for personnel access. The purge air system consists of fans, filters, and

associated piping and valves. The system has the safety function of containment isolation for

2-44
the purge penetration and is therefore within the scope of license renewal, based on the criteria

of 10 CFR 54.4(a)(1).

The CCS is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1) and

10 CFR 54.4(a)(2).

In Table 2.3.2.3 of the LRA, the applicant listed the CCS component types that are within the

scope of license renewal and subject to an AMR, including blower housing, bolting, cooling coil

assembly, cooling coil housing, damper housing, ductwork, piping, and valve.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Sections 2.1.1, 2.3.2.3, and 2.3.3.11 and ANO-2 UFSAR Sections 9.4.2

and 6.2.2 using the evaluation methodology described in Section 2.1 of this SER. The staff

conducted its review in accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4 (a); 'The staff then reviewed those that the applicant

identified as within the scope of license renewal to determine that the applicant did not omit

any passive and long-lived components that should be subject to an AMR, in accordance with

the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Sections 2.1.1, 2.3.2.3, and 2.3.3.11, the staff identified an area in which it

needed additional information to complete the review of the applicant's scoping and screening

results. Therefore, by letter dated April 8, 2004, the staff issued RAls, described below,

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1).

RAI 2.3-1 a

The staff requested that the applicant determine that the LRA has not omitted any CCS (RBHV

system and purge air system) SCs that should be within the scope of license renewal according

to 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation;.:

In its response, dated May 19,- 2004, the applicant stated that, in accordance with

10 CFR 54.21(a)(1), CCS (RBHV system and purge air system) SCs subject to an AMR are

those that perform an intended function without moving parts or a change in configuration or

properties (i.e., passive) and that are not subject to replacement based on a qualified life or,

specified time period (i.e., long-lived). Within the systems and structures within the scope of

license renewal, the applicant identified CCS (RBHV system and purge air system) SCs that are

subject to an AMR, in accordance with 10 CFR 54.21, in LRA Tables 2.2-1 a, 2.2-1 b, and 2.2-3.

The applicant conservatively considered these SCs to be within the scope of license renewal for

the purpose of identifying SCs that are subject to an AMR.

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Based on its review, the staff finds the applicant's response to RAI 2.3-1 a acceptable, because

the applicant considered all components within the CCS (RBHV system and purge air system),

as identified in LRA Tables 2.2-1 a and 2.2-1 b, and all CCS (RBHV system and purge air

system) structures identified in LRA Table 2.2-3, to be within the scope of license renewal for

the purpose of identifying SCs that are subject to an AMR. Therefore, the staff's concern

described in RAI 2.3-1a is resolved.

RAI 2.3-2

In Section 2.1.1 of the LRA, the applicant stated that it prepared LRA drawings (for the RBHV

system) to indicate components subject to an AMR; components for the CCS (RBHV system

and purge air system) that are subject to an AMR based only on the criteria of

10 CFR 54.4(a)(2) are not indicated on the LRA drawings for the CCS (RBHV system and

purge air system). The staff requested that the applicant determine that the LRA has not

omitted any CCS (RBHV system and purge air system) SCs that should be within the scope of

license renewal, according to 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1) and as stated in the response to RAI 2.1.1-2, it considered all components

for the CCS (RBHV system and purge air system) within the systems identified in LRA Tables

2.2-1 a and 2.2-1 b and all structures for the CCS (RBHV system and purge air system)

identified in LRA Table 2.2-3 to be within the scope of license renewal for the purpose of

identifying SCs for the CCS (RBHV system and purge air system) that are subject to AMR,

including components in the system considered only for 10 CFR 54.4(a)(2). '

Based on its review, the staff finds the applicant's response to RAI 2.3-2 acceptable, because

the applicant considered all components within the CCS (RBHV system and purge air system)

as identified in LRA Tables 2.2-1 a and 2.2-1 b, and all CCS (RBHV system and purge air

system) structures identified in LRA Table 2.2-3, to be within the scope of license renewal for

the purpose of identifying SCs that are subject to AMR. Therefore, the staff's concern

described in RAI 2.3-2 is resolved.

2.3.2.3.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the SCs of the CCS (RBHV system and purge air

system). Therefore, the staff concludes that the applicant has adequately identified the CCS

(RBHV system and purge air system) SCs that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the CCS (RBHV system and purge air system) SCs that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.2.4 Containment Penetrations

2.3.2.4.1 Summary of Technical Information in the Application

In Section 2.3.2.4 of the LRA, the applicant described the containment penetrations system.

The containment penetrations system isolates fluid systems that pass through containment

penetrations so as to confine radioactivity released following an accident to the containment.

For license renewal, the containment penetrations system includes the passive mechanical

penetration components that are not included in another system AMR. In general, if a system

has its own system-level AMR, then the associated containment penetrations are reviewed with

that system and not in this section.

This grouping of containment isolation components from various plant systems into one

consolidated review is appropriate, as indicated in Section 2.1.3.1 of the SRP-LR, which states,

"An applicant may take'an approach in scoping and screening that combines similar

components from various systems. For example, containment isolation valves from the various

systems may be identified as a single system for the purpose of license renewal." Section V.Cj

"Containment Isolation Components," of the'GALL Report recognizes the grouping and states,:-

"The system consists of isolation barriers in lines for BWR and PWR non-safety systems such

as the plant heating, waste gas, plant drain', liquid waste, and cooling water systems."

Containment penetrations are designed to provide at least a double barrier to the escape of

radioactive material at each fluid penetration through the containment liner plate. Double

barriers are provided to ensure that no single, credible failure or malfunction of an active or

passive system component can result in loss of isolation or significant leakage.

The electrical penetration nitrogen pressurization system provides continuous pressurization of

the electrical penetrations with the highest purity nitrogen. The system consists of two sets of

three seismically mounted nitrogen bottles, isolation valves, pressure relief valves, tubing, and

instrumentation.

Components in the steam generator sample and blowdown penetrations are required for safe

shutdown following a fire (10 CFR 50.48).

The containment penetrations system is within the scope of license renewal based on the

criteria of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3).

In Table 2.3.2-4 of the LRA, the applicant listed the containment penetration system component

types that are within the scope of license renewal and subject to an AMR, including bolting, flex

hose, piping, tubing, and valve.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and ANO-2 UFSAR Section 6.2.4 and Table 6.2-26

using the evaluation methodology described in Section 2.1 of this SER. The staff conducted its

review in accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff reviewed the'system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

2-47
- -

did not inadvertently omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4 (a). The staff then reviewed those that the applicant

identified as within the scope of license renewal to determine that the applicant did not omit any

passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

The staff found that the applicant included those portions of the containment penetration

system that meet the scoping requirements of 10 CFR 54.4 within the scope of license renewal

and identified them as such in LRA Section 2.3.2.4. Table 2.3.2-4 of the LRA includes the

containment penetration system's components that are subject to an AMR, in accordance with

10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff did not identify any omissions.

2.3.2.4.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and licensing

basis information, the staff did not identify any omissions or discrepancies in the applicant's

scoping and screening results for the SCs of the containment penetration system. Therefore,

the staff concludes that the applicant has adequately identified the containment penetration

system SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the containment penetration system SCs that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.5 Hydrogen Control

2.3.2.5.1 Summary of Technical Information in the Application

In Section 2.3.2.5 of the LRA, the applicant described the hydrogen control system. The

hydrogen control system limits the hydrogen gas concentration inside containment following a

LOCA. To assure that containment integrity is maintained, the hydrogen control system has the

following safety functions:

* removing hydrogen gas from the containment building atmosphere after a LOCA to

maintain the concentration of gases below the limits of flammability

* providing a direct reading of the concentration of hydrogen gas concentration in the

containment building

The hydrogen control system is an AMR system (see Section 2.2 of this SER), which includes

components from system codes hydrogen purge, hydrogen recombiners, RBHV, and radiation

monitoring system. As described in the SAR, these systems are the containment atmosphere

monitoring system, the hydrogen recombiner system, and the containment air recirculation

system.

The ANO-2 design originally included a hydrogen purge system that was intended to release

the postaccident containment atmosphere and reduce the hydrogen concentration by adding air

to containment. Since hydrogen recombiners are now used, a number of components are

spared in place. The hydrogen purge system includes valves that were originally intended to

supply service water under accident conditions to the purge components but now have only the

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safety function of maintaining the service water-pressure boundary. Section 2.3.3.8 of this SER

evaluates these valves with the service water system.

7, ;

The hydrogen recombiners are evaluated as an electrical system (see LRA Table 2.2-1 b).

The hydrogen control system is within the scope of license renewal, based on the criteria of

10 CFR154.4(a)(1).

In Table 2.3.2-5 of the LRA, the applicant listed the hydrogen control system component types

that are within the scope of license renewal and subject to an AMR, including bolting, filter

housing, heat exchanger (shell), heat exchanger (tubes), orifice, piping, pump casing, tubing,

and valve.

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and ANO-2 UFSAR Section 6.2.5 using the evaluation

methodology described in Section 2.1 of this SER. The staff conducted its review in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those that the applicant

identified as within the scope of license renewal to determine that the applicant did not omit any

passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.2.5, the staff identified an area in which it needed additional

information to complete the review of the applicant's scoping and screening results. Therefore,

by letter dated April 8, 2004, the staff issued an RAI, described below, concerning the specific

issues to determine whether the applicant has properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1).

RAI 2.3-5

The staff indicated that LRA Table 2.3.2-5 for hydrogen control system components subject to

an AMR does not list separators 2F-254 and 2F-256, shown on ANO-2 P&ID LRA-2261

Sheet 3, as components requiring an AMR. The staff requested that the applicant identify

where the LRA addresses the AMR for these components or justify their exclusion from an

AMR.

Applicant's Response and Staff's Evaluation.,

In its response, dated May 19, 2004, the applicant stated that separators 2F-254 and 2F-256

are subject to an AMR and are included under the component type "filter housing" in LRA Table

2.3.2-5. t . ..

Based on its review, the staff found the applicant's response to RAI 2.3-5 acceptable, because

the applicant considered all components within the hydrogen control system, as identified in

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LRA Section 2.3.2.5, and all hydrogen control system structures identified in LRA Table 2.3.2-5,

to be within the scope of license renewal for the purpose of identifying SCs that are subject to

AMR. Therefore, the staff considers its concern described in RAI 2.3-5 resolved.

2.3.2.5.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and licensing

basis information, the staff did not identify any omissions or discrepancies in the applicant's

scoping and screening results for the SCs of the hydrogen control system. Therefore, the staff

concludes that the applicant has adequately identified the hydrogen control system SCs that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the hydrogen

control system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3 Auxiliary Systems

In Section 2.3.3 of the LRA, the applicant identified the components of the auxiliary systems

that are subject to an AMR for license renewal. This section includes the following systems:

* spent fuel pool

* water suppression fire protection

* emergency diesel generator

* alternate ac diesel generator

* chemical and volume control

* Halon fire protection and reactor coolant pump motor oil leakage collection

* fuel oil

* service water

* auxiliary building ventilation

* control room ventilation

* miscellaneous systems within scope for 10 CFR 54.4(a)(2)

* other miscellaneous systems

2.3.3.1 Spent Fuel Storage

2.3.3.1.1 Summary of Technical Information in the Application

In Section 2.3.3.1 of the LRA, the applicant described the spent fuel storage. The subsystems

that make up the spent fuel pool system include fuel pool cooling and purification, spent fuel

pool, and fuel handling.

The fuel pool cooling and purification subsystem removes decay heat from the stored spent fuel

and maintains purity and optical clarity of the water in the spent fuel pool, the fuel transfer

canal, and the refueling canal. The subsystem consists mainly of nonsafety-related fuel pool

pumps, heat exchanger, filters, demineralizer, and associated piping and valves. The

subsystem contains nonsafety-related components whose failure could impact safety-related

components, and the system is therefore within the scope of license renewal based on the

criteria of 10 CFR 54.4(a)(2). Section 2.3.3.11 of this SER evaluates these components. The

safety-related components evaluated with this subsystem include components associated with

containment penetrations, a CVCS valve in the makeup to the spent fuel pool system, and

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components associated with the service water supply to the spent fuel pool. If system cooling

is lost, the seismic Class 1 service water system can provide water directly to the spent fuel

pool to maintain the level, which will boil off to cool the spent fuel assemblies. The spent fuel

pool cooling system piping and valves that supply service water to the spent fuel pool from the

#1 service water loop are safety' related. The redundant feed from the #2 service water loop

feeds directly to the spent fuel pool and does not route through spent fuel pool cooling

components. ,

The spent fuel pool subsystem stores new and spent fuel in a subcritical condition. Included in

this subsystem are the spent fuel racks and the new fuel racks. The new and spent fuel pool

racks are safety related and are required to support the fuel assemblies. Section 2.4.2 of this

SER evaluates the new fuel racks as a structural component.

The fuel handling subsystem provides the capability of (1) underwater handling and transfer of

spent fuel and control components removed from the reactor to the spent fuel pool, (2)

movement of fuel and control components within the reactor vessel, and (3) movement of new

fuel from the spent fuel pool to the reactor. !The subsystem also provides the capability to move

new fuel from shipping containers to new fuel storage or spent fuel storage.

The fuel handling subsystem consists of fuel handling equipment such as the fuel transfer tube,

the spent fuel pool crane, upender assemblies, refueling machine, spent fuel machine, the new

fuel elevator, and manual tools. The fuel transfer tube is a containment penetration and is

therefore safety related. Some of the fuel handling cranes, evaluated in Sections 2.4.1 and

2.4.2 of this SER, are seismic Class 1 in the parked position. The safety-related fuel transfer

tube gasket air test isolation valve is a service air system component which is evaluated with

the spent fuel pool system.

The spent fuel pool system is within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1-2).

In Table 2.3.3-1 of the LRA, the applicant listed the spent fuel storage component types that are

within the scope of license renewal and subject to an AMR, including bolting, fuel transfer tube,

piping, spent fuel racks, and valve.

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1, ANO-2 UFSAR Section 9.1, and site documentation in

its scoping and screening review of the spent fuel pool system. The staff conducted its review,

with the support from the plant audit and applicant's methodology-described in Section 2.3 of

this SER, in accordance with the guidance described in Section 2.3 of the SRPF-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and by reviewing site documentation to

determine that the applicant did not inadvertently omit from the scope of license renewal any

components with intended functions delineated under 10 CFR 54.4(a). In LRA Section

2.3.3.11, the applicant separately compiled all components with intended functions that are

within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews those

components for the spent fuel pool system in Section 2.3.3.11 of this SER. The staff then

reviewed those components that the applicant identified as having an intended function to

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determine that the applicant did not omit any passive and long-lived components that should be

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

On March 1 to 5, 2004, the NRC staff performed a scoping and screening inspection at ANO-2.

During a walkdown of the auxiliary building, the staff discovered a potential interaction between

a portion of the spent fuel pool cooling system, which the applicant had determined was not in

the scope of license renewal, and the emergency feedwater system (a safety-related system).

In particular, the staff found that a breech of the pump casing of the spent fuel pool cooling

pumps had the potential to spray two active components in the emergency feedwater system,

potentially adversely affecting it's ability to perform its safety function. In accordance with 10

CFR Part 54, if the failure of a nonsafety-related component could prevent a safety-related

function from being performed, that component should be in the scope of license renewal and

subject to an aging management review. The applicant subsequently included these pump

casings in their list of components in the spent fuel pool system requiring an aging

management review.

The NRC staff inspection identified an item requiring action by the applicant. The item listed

above is identified in the ANO-2 Inspection Report, dated April 19, 2004 (ML0411006481). The

applicant indicated that the spent fuel pool cooling pump casings were included in an aging

management program. The aging management review is discussed in Section 3.3.2.3.1. The

final disposition of this item will be addressed by the Aging Management Review Inspection

scheduled for November 1 - 19, 2004.

On the basis of its review, the staff found that, with the exception of the pump casings of the

spent fuel pool cooling pumps, the applicant has identified those portions of the spent fuel pool

system that meet the scoping requirements of 10 CFR 54.4 and included them within the scope

of license renewal in LRA Section 2.3.3.1. The applicant has also included the spent fuel pool

system components that are subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), in LRA Table 2.3.3-1.

2.3.3.1.3 Conclusion

During its review of the information provided in the LRA, site documentation, license renewal

drawings, and licensing basis information, the staff did not identify any omissions or

discrepancies in the applicant's scoping and screening results for the components of the spent

fuel pool system. During the scoping and screening inspection, the staff found that the

applicant had omitted the spent fuel pool cooling pump casings from the scope of license

renewal. The staff concluded that this was an isolated human error made in implementing the

scoping and screening methodology, and not indicative of a flawed scoping and screening

methodology. On the basis of its review, the staff concludes that the applicant has adequately

identified the spent fuel pool system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the spent fuel pool system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.2 Water Suppression Fire Protection

2.3.3.2.1 Summary of Technical Information'irithe Application

In Section 2.3.3.2 of the LRA, the applicant'described the water suppression fire protection

system. The fire protection system protects plant personnel and equipment in the event of a

fire to ensure the safe shutdown of the plant and to minimize the risk of a release of radioactive

material to the environment. Overall fire protection features include fire suppression, fire

detection and actuation, and fire barriers. The fire detection and actuation portion of the system

is screened as part of the electrical and l&C system. Fire dampers are screened as part of the

assigned HVAC system. Other passive fire barriers'are screened as part of the structures.

The fire protection system includes both manual (e.g., use of hoses, portable extinguishers, and

fixed systems by plant personnel) and automatically actuated fire suppression features.

Depending on the area protected, the suppression system employs extinguishing agents

consisting of water and/or Halon. The water suppression fire protection system includes the fire

pumps (including the diesel-driven fire pump'fuel oil and other auxiliary systems), the fire water

distribution system (including outside loop yard mains, hydrants, hose stations, standpipes, and

valves), and deluge and preaction sprinkler systems.

Portable fire protection equipment, such as fire hoses, fire extinguishers, carbon dioxide bottles,

and self-contained breathing apparatus air bottles, is not subject to an AMR because it is.

considered short-lived, replaced on condition, and exempted from AMR consistent with the

treatment of consumables.

Table 2.2-la of the LRA lists the mechanical systems within the scope of license renewal,

including the water fire suppression system. The applicant identified the 10 CFR 54.4(a)(1-3)

fire protection regulated event criteria as the scoping criteria that were met by the fire protection

system components which are within the scope oflicense renewal.

In Table 2.3.3-2 of the LRA, the applicant listed the fire protection component types that arewithin the scope of license renewal and subject to an AMR, including air dryer housing, blower

housing, bolting, ductwork,' expansion joint, filter, filter housing, flex hose, gear housing,

governor housing, heat exchanger (housing); heat exchanger (shell), heat exchanger (tubes),

heater housing, nozzle, orifice, pipe/fittings, piping', pump casing, tubing, and valve.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2'and ANO-2 UFSAR Section 9.5.1;. The staff conducted

its review, using the evaluation methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In the performance of the review, the staff, using the scoping process described in Section 2.3

of this SER, reviewed the UFSAR to determine if the applicant failed to identify in the LRA any

system functions, in accordance with the requirements of 10 CFR 54.4(a), as an'intended

function of the fire protection system. The staff then reviewed the LRA and UFSAR, in

accordance with the screening process described in Section 2.3 of this SER, to determine that

the applicant did not omit'any passive and long-'lived components from an AMR, in accordance

with 10 CFR 54.21 (a)(1).

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- .

The staff found that the applicant included those portions of the water suppression fire

protection system that meet the scoping requirements of 10 CFR 54.4 within the scope of

license renewal and identified them as such in LRA Section 2.3.3.2. Table 2.3.3-2 of the LRA

includes the water suppression fire protection system components that are subject to an AMR,

in accordance with 10 CFR 54.4(a) and 10 CFR 54.21(a)(1). The staff did not identify any

omissions.

2.3.3.2.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant failed to identify any SSCs that should be within the scope of license

renewal. The staff did not identify any omissions. In addition, the staff performed an

independent assessment to determine if the applicant identified all components that should be

subject to an AMR. The staff did not identify any omissions. On the basis of its review, the

staff concludes that the applicant has adequately identified the components of the fire

protection system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and the components of the fire protection system that are 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

In Section 2.3.3.3 of the LRA, the applicant described the EDG system. The EDG system

provides redundant emergency power sources capable of furnishing adequate power to safely

shut down the reactor, remove reactor residual heat, and maintain the unit in a safe-shutdown

condition upon the loss of preferred power with or without a coincident design-basis event. The

EDGs are the redundant emergency power sources. The EDG system consists of diesel

generators and the starting air, cooling water, lubrication, and combustion air intake and

exhaust subsystems. Section 2.3.3.7 of this SER evaluates the fuel oil storage and transfer

subsystem associated with the EDG.

The system is the safety-related source of electrical power required for engineered safety

feature loads during design-basis events. The system also provides the emergency power

required for safe shutdown following a fire. The EDG system is therefore within the scope of

license renewal, based on the criteria of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3).

In Table 2.3.3-3 of the LRA, the applicant listed the EDG system component types that are

within the scope of license renewal and subject to an AMR, including blower housing, bolting,

booster housing, distributor housing, ejector, expansion joint, filter, filter housing, flex hose,

governor housing, heat exchanger (bonnet), heat exchanger (shell), heat exchanger (tubes),

heat exchanger (tubesheet), heater housing, orifice, piping, pump casing, silencer, tank,

thermowell, tubing, unloader, and valve.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, ANO-2 UFSAR Sections 8.3.1.1.7 and 9.5.5 through

9.5.9, and site documentation in its scoping and screening review of the EDG system. The staff

conducted its review, with the support from the plant audit and applicant's methodology

2-54
described in Section 2.3 of this SER, in accordance with the guidance described in Section 2.3

of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documentation to

determine that the applicant did not inadvertently omit from the scope of license renewal any

components with intended functions delineated under 10 CFR 54.4(a). In LRA Section

2.3.3.11, the applicant separately compiled all components with intended functions that are

within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews those ^

components for the EDG system in Section 2.3.3.11 of this SER. The staff then reviewed those

components that the applicant identified as having an intended function to determine that the

applicant did not omit any passive and long-lived components that should be subject to an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.3.3 and site documentation, the staff identified an area in which it'

needed additional information to complete the review of the applicant's scoping and screening

results. Therefore, by letter dated May 11;:2004, the staff issued an RAI, described below, to

the applicant to determine whether it has properly applied the scoping criteria of

10 CFR 54.4(a).

RAI 2.3.3.3-1 (a)

The staff identified several active components that are highlighted on license renewal drawings

as subject to an AMR. For the EDG system, these include exhaust turbo chargers and EDG

engines 2K-4A and 2K-4B. Table 2.3.3-3 of the LRA does not include these as components

subject to an AMR. In LRA Section 2.1.1, the applicant stated that all components highlighted

on license renewal boundary drawings are subject to an AMR. The staff requested that the

applicant clarify if the highlighted active components -are subject to an AMR. If so, the staff

requested that the applicant justify their exclusion from LRA Table 2.3.3-3, or include the

components in LRA Tables 2.3.3-3 and 3.3.2-3.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that LRA Tables 2.3.3-3 and 3.3.2-3

show the passive portion of the turbo chargers as the component type "blower housing." The

applicant also stated that EDG engines 2K.4A and 2K-4B, in accordance with Appendix B to

NEI 95-10 and consistent with SRP-LR Table 2.1-5, are not subject to an AMR and as such

should not be highlighted on the drawing:.-

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-1 (a) acceptable,

because the turbo charger housings which are passive and long-lived are appropriately

included within the scope and are subject to an AMR. As such, LRA Tables 2.3.3-3 and 3.3.2-3

include them as blower housings. The applicant made an error in highlighting the active

components in question on the license red&iWal drawing; therefore, they are not subject to an

AMR. This determination is acceptable. Therefore, the staff considers its concern described in

RAI 2.3.3.3-1 (a) resolved,,as it relates to the EDG system.

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2.3.3.3.3 Conclusion

During its review of the information provided in the LRA, site documentation, the license

renewal drawings, and licensing basis information, the staff did not identify any omissions or

discrepancies in the applicant's scoping and screening results for the components of the EDG

system. Therefore, the staff concludes that the applicant has adequately identified the EDG

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the EDG system components that are subject to AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.4 Alternate ac Diesel Generator

2.3.3.4.1 Summary of Technical Information in the Application

In Section 2.3.3.4 of the LRA, the applicant described the alternate ac diesel generator system,

which provides backup power at ANO. The alternate ac generator is a 4400-kilowatt (kW)

diesel generator installed in response to the regulatory requirements of 10 CFR 50.63. The

alternate ac system consists of a single diesel generator and the air start, engine cooling water,

lubrication, combustion air intake and exhaust, fuel oil, and alternate ac building heating and

ventilation subsystems. Ventilation components are part of the ventilation system code (VENT).

While it does not have a safety function, 10 CFR 50.63 requires the alternate ac generator

system. The system is nonsafety related. The alternate ac generator system is credited for

providing power during a loss of offsite power concurrent with a loss of the EDGs (i.e., SBO).

The alternate ac diesel can furnish adequate power to safely shut down the reactor upon a loss

of all ac power at ANO-2 by connecting to either of the 4160-V safety-related buses on the unit.

The alternate ac diesel is also credited with providing electrical power for operation for safe

shutdown after a fire. Therefore the alternate ac system is within the scope of license renewal,

based on 10 CFR 54.4(a)(3), for the fire protection and SBO regulated events.

The alternate ac generator is shared with ANO, Unit 1 (ANO-1). To have a complete review of

the components required for ANO-2 operation, the SER evaluates portions of the system that

are required to support the supply of power to ANO-2 even if they have already been reviewed

for ANO-1 license renewal.

In Table 2.3.3.4 of the LRA, the applicant listed the alternate ac diesel system component types

that are within the scope of license renewal and subject to an AMR, including air motor housing,

blower housing, bolting, expansion joint, filter, filter housing, flex hose, governor housing, heat

exchanger (shell), heat exchanger (tubes), heater housing, indicator housing, lubricator

housing, orifice, piping, pump casing, silencer, tank, thermowell, tubing, and valve.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4, ANO-2 UFSAR Section 8.3.3, and site documentation

in its scoping and screening review of the alternate ac diesel generator system. The staff

conducted its review, with the support from the plant audit and applicant's methodology

described in Section 2.3 of this SER, in accordance with the guidance described in Section 2.3

of the SRP-LR.

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In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documentation to confirm

that the applicant did not inadvertently omit from the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the X

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews

those components for the alternate ac diesel generator system in Section 2.3.3.11. of this SER.

The staff then reviewed those components that the applicant identified as having an intended

function to determine that the applicant did not omit any passive and long-lived components

that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.3.4 and site documentation, the staff identified areas in which it

needed additional information to complete its evaluation of the applicant's scoping and

screening results; Therefore, by letter dated May 11, 2004, the staff issued RAIs, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1).

RAI 2.3.3.3-1 (b)

The staff identified several active components that the applicant highlighted on the license

renewal drawings as subject to an AMR; Forthe alternate ac generator system, these include

cylinder block and head, piston cooling jets (housing), engine sump, bearings (housing); and

turbo chargers. Table 2.3.3-4 of the LRA does not list these as components subject to an AMR.

In LRA Section 2.1.1, the applicant stated that all components highlighted .on license renewal

boundary drawings are subject to an AMR.! The staff requested that the applicant clarify if }

these highlighted active components are subject to an AMR. If so, the staff requested that the

applicant justify their exclusion from LRA Table 2.3.3-4, or include these components in LRA

Tables 2.3.3-4 and 3.3.2-4.

Applicant's Response and Staff's Evaluation

In the response dated June 10, 2004, the applicant stated that LRA Tables 2.3.3-4 and 3.3.2-4

show the passive portion of the turbo chargers as the component type "blower housing." The

applicant also stated that it inadvertently highlighted the cylinder block and head, the bearings,

piston cooling jets, and sump. These components are part of the alternate ac diesel generator

engine assembly which, in accordance with Appendix B to NEI 95-10 and consistent withSRP-LR Table 2.1-5, are not subject to an AMR. Therefore, LRA Tables 2.3.3-4 and 3.3.2-4 do

not include these components. -

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-1 (b) acceptable,

because the applicant appropriately included the turbo charger housings, which are passive and

long-lived, within the scope of license renewal and as subject to an AMR.. As such, LRA Tables

2.3.3-4 and 3.3.2-4 include them as blower housings. The applicant made an error in

highlighting the active-components in question on the drawings; therefore, they are not subject

to an AMR. This determination is consistent with the SRP-LR and, as such, acceptable.

Therefore, the staff considers its concern described in RAI 2.3.3.3-1 (b) resolved, as it relates to

the alternate ac generator system.

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RAI 2.3.3.4-1

Section 8.3.3, "Alternate AC Power Source," of the ANO-2 UFSAR states that the engine

generator set has Class F insulation, and that license renewal drawing LRA-2241, Sheet 2,

shows the insulated piping as not subject to an AMR. The staff requested that the applicant

briefly state the basis for excluding this insulation from within the scope of license renewal (e.g.,

system efficiency, heat load calculations, or EQ purposes). The insulation is passive and

long-lived and should be subject to an AMR, in accordance with the requirements of

10 CFR 54.21 (a)(1), if it is relied upon for EQ purposes. The staff requested that the applicant

verify whether the Class F insulation is subject to an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that the insulation referred to in

UFSAR Section 8.3.3 is on the generator windings and is not piping insulation. As part of the

alternate ac generator system, the generator and the piping are within the scope of license

renewal. However, the generator with its associated insulation is an active component that is

not subject to an AMR. The insulation shown on exhaust piping on the referenced drawing,

though not specifically highlighted, is subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-1 acceptable for the

generator insulation because the insulation referred to in UFSAR Section 8.3.3 is part of the

generator which is an active component and, therefore, not subject to an AMR. The staff finds

the applicant's response to RAI 2.3.3.4-1 acceptable for the insulation on the exhaust piping,

which is in scope and subject to an AMR with the component type "insulation." Therefore, the

staff considers its concern described in RAI 2.3.3.4-1 resolved.

2.3.3.4.3 Conclusion

During its review of the information provided in the LRA, site documentation, license renewal

drawings, and licensing basis information, the staff identified one omission in the applicant's

scoping and screening results for insulation of the alternate ac diesel generator system. The

staff determined that this error was not indicative of a flawed scoping and screening

methodology. Therefore, the staff concludes that the applicant has adequately identified the

alternate ac diesel generator system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the alternate ac diesel generator system components that

are subject to AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.5 Chemical and Volume Control

2.3.3.5.1 Summary of Technical Information in the Application

In Section 2.3.3.5 of the LRA, the applicant described the CVCS. The CVCS maintains RCS

inventory and controls RCS chemistry. The CVCS system consists of four subsections,

including letdown, charging, boron addition, and reactor makeup water. The CVCS also

supplies borated water to the RCS from the boric acid makeup tanks or the RWT via the

charging pumps.

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The components in this system are mostly nonsafety related, but safety-related components

include the containment isolation valves, part of the RCS pressure boundary, or boundary

valves to safety-related systems. The CVCS contains nonsafety-related components,

evaluated in Section 2.3.3.11 of this SER, whose failure could impact safety-related

components. , - i: I

This system is credited as one method of providing RCS inventory addition for safe shutdown

following a fire with the suction supplied from the RWT or the boric acid makeup tanks. These

components perform a function that demonstrates compliance with the Commission's

regulations for fire protection (10 CFR 50.48).!

Section 2.3.1 of this SER evaluates the portions of the CVCS that are part of the RCS pressure

boundary with the RCS. Section 2.3.2.1 of this SER evaluates the CVCS valve in the supply

from the RWT with the ECCS. Finally, Section 2.3.3.1 of this SER evaluates the CVCS valves

in the makeup to the spent fuel pool system with the spent fuel pool system. The CVCS

evaluation includes components from the nitrogen supply system that are associated with the,

charging pump pulsation dampeners and suction stabilizers. The CVCS is within the scope of

license renewal based on the criteria of 10 CFR 54.4(a)(1-3).

In Table 2.3.3.5 of the LRA, the applicant listed the CVCS system component types that are

within the scope of license renewal and subject to an AMR, including bolting, gear housing,

heat exchanger (shell), piping, pump casing 'sight glass, sight glass (housing), tank,

thermowell, tubing, and valve.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5, Table 2.3.3-5, and SAR Section 9.3.4 to determine

whether thie applicant identified the CVCS subsystems (e.g., piping, tanks, and pump casing)

and supporting-structures that are within the scope of license renewal and subject to AMR, in

accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a). The staff used the

evaluation methodology described in Section 2.3 of this SER. The staff conducted its review in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54:4(a), to determine that the applicant

did not inadvertently omit from the scope of license renewal any CVCS components with

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed the CVCS;

components that the applicant identified as within the scope of license renewal to confirm that

the applicant did not omit any passive and long-lived components that should be subject to an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). The staff did not identify any

omissions.

2.3.3.5.3 Conclusion

During its review of the information provided in the'LRA, license renewal drawings,

and licensing basis information, the staff did not identify any omissions or discrepancies

in the applicant's scooping and screening results for the CVCS. Therefore, the staff concludes

that the applicant has adequately identified the CVCS components that are within the scope

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- - -

of license renewal, as required by 10 CFR 54.4(a), and the CVCS system SCs that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.6 Halon Fire Protection and Reactor Coolant Pump Motor Oil Leakage Collection

2.3.3.6.1 Summary of Technical Information in the Application

In Section 2.3.3.6 of the LRA, the applicant described the Halon fire protection system and the

RCP motor oil collection system. The Halon fire protection system provides fire suppression in

the core protection calculator room, flooding the room with Halon 1301 to extinguish a fire. The

Halon system consists of Halon storage tanks, discharge piping, valves, controls, alarms, and

smoke detectors. The RCP motor oil collection system collects random leakage from the four

RCP motors to reduce the chance of a fire. Each sump tank has the capacity to contain the

lube oil inventory of a single RCP.

Table 2.2-1 a of the LRA lists the mechanical systems within the scope of license renewal,

including the Halon fire suppression system and the RCP motor oil collection system. The

applicant identified the 10 CFR 54.4(a)(3) fire protection regulated event criteria as the scoping

criteria that are met by the fire protection system components which are within the scope of

license renewal.

In Table 2.3.3-6 of the LRA, the applicant listed the fire protection component types that are

within the scope of license renewal and subject to an AMR, including bolting, flex hose,

indicator housing, nozzle, pan, piping, tank, tubing, and valve.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and ANO-2 UFSAR Sections 9.5.1.2 and 9.5.1.3. The

staff conducted its review, using the evaluation methodology described in Section 2.3 of this

SER, in accordance with the guidance described in Section 2.3 of the SRP-LR.

In the performance of the review, the staff, using the scoping process described in Section 2.3

of this SER, reviewed the UFSAR to determine if the applicant failed to identify in the LRA any

system functions, in accordance with the requirements of 10 CFR 54.4(a), as an intended

function of the fire protection system. The staff then reviewed the LRA and UFSAR, in

accordance with the screening process described in Section 2.3 of this SER, to confirm that the

applicant did not omit any passive and long-lived components that are subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff found that the applicant identified those portions of the Halon fire protection system

and RCP motor oil collection system that meet the scoping requirements of 10 CFR 54.4 as

within the scope of license renewal and included them in LRA Section 2.3.3.6. The applicant

included the Halon fire protection system components and RCP motor oil collection system

components that are subject to an AMR, in accordance with 10 CFR 54.4(a) and

10 CFR 54.21(a)(1), in LRA Table 2.3.3-6. The staff did not identify any omissions.

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2.3.3.6.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant failed to identify any SSCs that should be within the scope of license

renewal. The staff did not identify any omissions.- In addition, the staff performed an - -

independent assessment to determine whether the applicant failed to identify any components

that should be subject to an AMR. The staff did not identify any omissions. On the basis of its

review, the staff concludes that the applicant has adequately identified the components of the

fire protection system that are within the scope of license renewal, as required by .10 CFR

54.4(a), and the components of the fire protection system that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.3.7 Fuel Oil

2.3.3.7.1 Summary of Technical Information in the Application

In Section 2.3.3.7 of the LRA, the applicant'described the fuel oil system. The fuel oil system

provides fuel oil for site components, including the various diesel engines and the auxiliary

boiler. The system consists of various tanks; pumps, injectors, piping, and valves to store and

transfer fuel oil.

The system contains components that are the safety-related source of diesel fuel as required

for emergency diesel operation during design-basis events. The system provides diesel fuel as

required to the alternate ac generator for the'SBO.event. The fuel oil to the fire diesel, the

emergency generators, and alternate ac generators is credited for the safe-shutdown fire

regulated event.

The fuel oil system includes ANO-1 shared components, such as the bulk fuel oil storage tank.

To have a complete review of components required for ANO-2 operation, components --

necessary for providing fuel oil to the systems required for ANO-2 are evaluated even if they

have already been reviewed for ANO-1 license renewal. The ANO-1 fuel oil system is credited

as a backup supply to the ANO-2 diesel generators in the case of a fire that renders the ANO-2

fuel oil transfer pumps unavailable.

The fuel oil system includes safety-related components and is therefore within the scope of

license renewal, based on 10 CFR 54.4(a)(1). The fuel oil system is required for compliance

with the Commission's regulations for fire protection (10 CFR 50.48) and SBO events.

Therefore, it is within the scope of license renewal based on 10 CFR 54.4(a)(3).

In Table 2.3.3.7 of the LRA, the applicant listed the compressed air component types that are

within the scope of license renewal and subject to an AMR, including bolting, filter, filter

housing, flame arrestor, flex hose, heat exchanger (shell), heat exchanger (tubes), indicator

housing, injector housing, orifice, piping, pump casing, tank, thermowell, tubing, and valve.

2.3.3.7.2 Staff Evaluation .

* ,\ I; , . . .

The staff reviewed LRA Section 2.3.3.7, ANO-2 UFSAR Sections 8.3.3.2.3.3, 9.5.1, and 9.5.4,

and site documentation in its scoping and screening review of fuel oil system. The staff

conducted its review, with the support from the plant audit and applicant's methodology

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described in Section 2.3 of this SER, in accordance with the guidance described in Section 2.3

of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documentation to confirm

that the applicant did not inadvertently omit from the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 1 0 CFR 54.4(a)(2). The staff reviews

those components for the fuel oil system in Section 2.3.3.11 of this SER. The staff then

reviewed those components that the applicant identified as having an intended function to

confirm that the applicant did not omit any passive and long-lived components that should be

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 the applicant has identified those portions of the

fuel oil system that meet the scoping requirements of 10 CFR 54.4 and included them within the

scope of license renewal in LRA Section 2.3.3.7. The applicant has also included the fuel oil

system components that are subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), in LRA Table 2.3.3-7. The staff did not identify any

omissions.

2.3.3.7.3 Conclusion

During its review of the information provided in the LRA, site documentation, license renewal

drawings, and licensing basis information, the staff did not identify any omissions or

discrepancies in the applicant's scoping and screening results for the components of the fuel oil

system. Therefore, the staff concludes that the applicant has adequately identified the fuel oil

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the fuel oil system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.8 Service Water

2.3.3.8.1 Summary of Technical Information in the Application

In Section 2.3.3.8 of the LRA, the applicant described the service water system. The service

water system provides cooling water from Lake Dardanelle or the emergency cooling pond to

safety-related and nonsafety-related equipment, as well as an emergency supply of water to the

emergency feedwater system and the fuel pool system. The service water system provides

cooling water to two independent flowpaths, which furnish water to two independent, safetyrelated engineered safety features equipment trains and two nonsafety-related flowpaths

(auxiliary cooling water and component cooling water heat exchangers/main chillers). Three

service water pumps supply the various components cooled by service water.

The service water system is the safety-related source of cooling water for equipment cooling

during design-basis events. The system contains nonsafety-related components, evaluated in

Section 2.3.3.11 of this SER, whose failure could impact safety-related components. The

service water system is required to function following a fire for safe shutdown of the unit.

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The emergency feedwater suction supply valves from the service water system are evaluated

with the service water system. The service water evaluation als6 includes hydrogen control

system valves that were originally intended to supply service water under accident conditions to

the purge components but now only have the safety function of maintaining the service water

pressure boundary. Ventilation components that provide cooling for the service water pumps

and motors are classified as part of the intake structure system but are evaluated with the

service water system. The individual service water supplied heat exchangers are evaluated

with the systems that they cool.

The service water system is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(1)-(3).

In Table 2.3.3-8 of the LRA, the applicant listed the service water component types that are

within the scope of license renewal and subject to an AMR, including blower housing, bolting,

damper housing, ductwork, expansion joint, filter, filter housing, flow straightener, orifice, piping,

pump casing, thermowell, tubing, and valve.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8, ANO-2 UFSAR Sections 9.2.1, 9.2.5, 3.6.4.5.1.1, and

9.4.6, and site documentation in its scoping and screening review of the service water system.

The staff conducted its review, with the support from the plant audit and applicant's

methodology described in Section 2.3 of this SER, in accordance with the guidance described

in Section 2.3 of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documents to confirm

that the applicant did not inadvertently omit from the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews

those components for the service water system in Section 2.3.3.11 of this SER. The staff then

reviewed those components that the applicant identified as having an intended function to

confirm that the applicant did not omit any passive and long-lived components that should be

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 the applicant has identified those portions of the

service water system that meet the scoping requirements of 10 CFR 54.4(a) and included them

within the scope of license renewal in LRA Section 2.3.3.8. The applicant also included the

service water system components that are subject to an AMR, in accordance with

10 CFR 54.21 (a)(1), in LRA Table 2.3.3-8. fThe staff did not identify any omissions.

2.3.3.8.3 Conclusion

During its review of the information provided in the LRA, site documentation, license renewal

drawings, and licensing basis information,.the staff did not identify any omissions or

discrepancies in the applicant's scoping and screening results for the components of the spent

fuel pool system. Therefore, the staff concludes that the applicant has adequately identified the

service water system components that are within the scope of license renewal, as required by

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10 CFR 54.4(a), and the service water system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.9 Auxiliary Building Ventilation

2.3.3.9.1 Summary of Technical Information in the Application

In Section 2.3.3.9 of the LRA, the applicant described the auxiliary building ventilation. The

auxiliary building ventilation system provides ventilation for equipment in the auxiliary building

and the auxiliary building extension. The system consists of safety-related and nonsafetyrelated equipment in the auxiliary building to provide both normal and emergency cooling and

ventilation. The system includes the auxiliary building heating and ventilation system code.

The auxiliary building is served by separate ventilation systems for each of the following areas:

* fuel handling floor radwaste area

* auxiliary building radwaste area (includes electrical equipment room 2096)

* noncontaminated areas

* emergency diesel generator rooms

* battery rooms and direct current equipment rooms

* switchgear rooms

* cable spreading room and electrical equipment room 2108

* computer room 2098-C

* electrical MG room 2076

* ventilation equipment room

* main steamline enclosure

* elevator-machine room

* boiler room area

* heat exchanger and pipeway area

* electrical equipment room 2091

The components within these subsystems include supply and exhaust fans, cooling and heating

coils, dampers, filters, ductwork, condensing units, and dehumidifiers.

Safety-related ventilation systems serve areas containing safety-related equipment, including

the HPSI pumps, the charging pumps, the shutdown cooling heat exchangers, the emergency

feedwater pumps, electrical equipment (rooms 2091 and 2096), the EDGs, batteries, and

switchgear.

This system contains nonsafety-related components, evaluated in Section 2.3.3.11, whose

failure could impact safety-related components. The cooling for some components, such as the

EDG room and the safety parameters display system room, is required to support safe

shutdown following a fire. The fire dampers included in this system are required for fire

protection (10 CFR 50.48).

Section 2.3.3.10 of this SER evaluates components in the auxiliary building heating and

ventilation system code that support control room ventilation with control room ventilation.

The system is within the scope of license renewal based on 10 CFR 54.4(a)(1)-(3).

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In Table 2.3.3-9 of the LRA, the applicant listed the auxiliary ventilation system component

types that are within the scope of license renewal and subject to an AMR, including blower

housing, bolting, cooling coil housing, damper housing, ductwork, expansion joint, heat

exchanger (tubes), piping, tubing, and valve. -

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Sections 2.1.1,2.3.3.9, and 2.3.3.11 and ANO-2 UFSAR Section 9.4.2

using the evaluation methodology described in Section 2.1 of this SER. The staff conducted its

review in accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirements of 10 CFR 54.4(a), to confirm that the applicant

did not'inadvertently omit from the scope of license renewal any components with intended ;

functions delineated under 10 CFR 54.4 (a).- The staff then reviewed those that the applicant

identified as within the scope of license renewal to confirm that the applicant did not omit any.

passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1). I.

In reviewing LRA Sections 2.1.1, 2.3.3.9, and 2.3.3.11, the staff identified an area in which it

needed additional information to complete the review of the applicant's scoping and screening

results. Therefore, by letter dated April 8, 2004, the staff issued RAls, described below,

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1).

RAI 2.3-1b

The staff requested that the applicant determine that the LRA has not omitted any auxiliary

building ventilation system SCs that should be within the scope of license renewal, according to

10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), auxiliary building ventilation system SCs subject to AMR are those that

perform an intended function without moving parts or a change in configuration or properties

(i.e., passive) and that are not subject to replacement based on a qualified life or-specified time

period (i.e.' long-lived). Among the systems'and structures within the scope of license renewal,

the applicant identified the auxiliary building ventilation system SCs that are subject to an AMR,

in accordance with 10 CFR 54.21, in LRA Tables 2.2-1 a, 2.2-1 b, and 2.2-3. The applicant

conservatively'considered them to be within the scope of license renewal for the purpose of

identifying SCs that are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3-1 b acceptable, because

the applicant considered all components within the auxiliary building ventilation system as

identified in LRA Tables 2.2-1 a and 2.2-1 b, and all auxiliary building ventilation system

structures identified in LRA Table 2.2-3, to be within the scope of license renewal for the

purpose of identifying SCs that are subject to AMR. Therefore, the staff's concern described in

RAI 2.3-1b is resolved.

2-65
RAI 2.3-2

In LRA Section 2.1.1, the applicant stated that it prepared LRA drawings (for the auxiliary

building ventilation system) to indicate components subject to an AMR. The applicant did not

indicate components (for the auxiliary building ventilation system) that are subject to an AMR

based only on the criteria of 10 CFR 54.4(a)(2) on the LRA drawings (for the auxiliary building

ventilation system). The staff requested that the applicant determine that the LRA has not

omitted any auxiliary building ventilation system SCs that should be within the scope of license

renewal, according to 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), as given in the response to RAI 2.1.1-2, it considered all components (for

the auxiliary building ventilation system) within the systems identified in LRA Tables 2.2-1 a and

2.2-1 b, and all structures (for the auxiliary building ventilation system) identified in LRA Table

2.2-3, to be within the scope of license renewal for the purpose of identifying SCs (for the

auxiliary building ventilation system) that are subject to AMR, including components in the

system considered only in response to 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant's response to RAI 2.3-2 acceptable, because

the applicant considered all components within the auxiliary building ventilation system as

identified in LRA Tables 2.2-1 a and 2.2-1 b, and all auxiliary building ventilation system

structures identified in LRA Table 2.2-3, to be within the scope of license renewal for the

purpose of identifying SCs that are subject to AMR. Therefore, the staff's concern described in

RAI 2.3-2 is resolved.

RAI 2.3-3.b

The staff requested that the applicant clarify whether sealants used as a pressure boundary

function for the auxiliary building ventilation system 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).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that it did not credit sealants with a

function of pressure boundary for the auxiliary building ventilation system. Sealants used in the

auxiliary building ventilation system do not perform a license renewal intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3-3.b acceptable, because

the applicant did not credit sealants to perform any pressure boundary function for the auxiliary

building ventilation system and, as such, sealants do not perform a license renewal intended

function. Therefore, the staff's concern described in RAI 2.3-3.b is resolved.

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2.3.3.9.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the SCs of the auxiliary building ventilation

system. Therefore, the staff concludes that the applicant has adequately identified the auxiliary

building ventilation system SCs that are within' the scope of license renewal, as required by

10 CFR 54.4(a), and the auxiliary building ventilation system S~s that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).-

2.3.3.10 Control Room Ventilation

2.3.3.10.1 Summary of Technical Information in the Application

In Section 2.3.3.10 of the LRA, the applicant described the control room ventilation system,

which provides a suitable environment for equipment and personnel in the control room.§'The

system contains normal and emergency operation trains that include ductwork, filter units,

blowers, cooling units, and heat exchangers to supply the control room space with the proper

heating or cooling and limit the postaccident dose rate to the operators.

The control room ventilation system is the safety-related source of ventilation required for

control room cooling during design-basis events. It provides protection from emergency events,

such as a toxic gas release. The system contains fire dampers that must close to isolate the

control room in the event of a fire. These dampers are required for compliance with the

Commission's regulations for fire protection (10 CFR 50.48).

This system is shared with ANO-1. To have a complete review of the components required for

ANO-2 operation, the components necessary for providing cooling for ANO-2 are evaluated

even if they have already been reviewed for ANO-1 license renewal. This evaluation includes

the safety-related components of the chilled water system that support control room ventilation.

The control room ventilation system is within the scope of license renewal, based on the criteria

of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3).'-

In Table 2.3.3.10 of the LRA, the applicant listed the auxiliary and radwaste area ventilation

system component types that are within the scope of license renewal and subject to an AMR,

including blower housing, bolting, compressor casing, cooling coil housing, damper housing,

ductwork, expansion joint, filter housing, heat exchanger (bonnet), heat exchanger (shell), heat

exchanger (tubes), indicator housing, piping, sight glass, sight glass (housing), silencer, tank,-

thermowell, tubing, and valve'..

2.3.3.10.2 Staff Evaluation -.

The staff reviewed LRA Sections 2.1.1 and 2.3.3.10 and ANO-2 UFSAR Section 9.4.2 using the

evaluation methodology described in Section 2.1 of this SER. The staff conducted its review in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In conducting the review, the staff evaluated the system functions described in the LRA and

UFSAR, in accordance with the requirementsbof 10 CFR 54.4(a), to confirm that the applicant

did not inadvertently omit from the scope of license renewal any components with intended

2-67
functions delineated under 10 CFR 54.4(a). The staff then reviewed those that the applicant

identified as within the scope of license renewal to confirm that the applicant did not omit any

passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Sections 2.1.1 and 2.3.3.10, the staff identified an area in which it needed

additional information to complete its evaluation of the applicant's scoping and screening

results. Therefore, by letter dated April 8, 2004, the staff issued RAls, described below,

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1).

RAI 2.3-1c

The staff requested that the applicant determine that the LRA has not omitted any control room

ventilation system SCs that should be within the scope of license renewal, according to

10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), control room ventilation system SCs subject to AMR are those that perform

an intended function without moving parts or a change in configuration or properties (i.e.,

passive) and that are not subject to replacement based on a qualified life or specified time

period (i.e., long-lived). Among the systems and structures within the scope of license renewal,

the applicant identified control room ventilation system SCs that are subject to an AMR, in

accordance with 10 CFR 54.21, in LRA Tables 2.2-1a, 2.2-1b, and 2.2-3. The applicant

conservatively considered them to be within the scope of license renewal for the purpose of

identifying SCs that are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3-1c acceptable, because

the applicant considered all components within the control room ventilation system as identified

in LRA Tables 2.2-1 a and 2.2-1 b, and all control room ventilation system structures identified in

LRA Table 2.2-3, to be within the scope of license renewal for the purpose of identifying SCs

that are subject to an AMR. Therefore, the staff's concern described in RAI 2.3-1 c is resolved.

RAI 2.3-2

In Section 2.1.1 of the LRA, the applicant stated that it prepared LRA drawings (for the control

room ventilation system) to indicate components subject to an AMR. The LRA drawings (for the

control room ventilation system) do not indicate the components (for the control room ventilation

system) that are subject to an AMR based only on the criteria of 10 CFR 54.4(a)(2). The staff

requested that the applicant determine that the LRA has not omitted any control room

ventilation system SCs that should be within the scope of license renewal, according to

10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), as noted in the response to RAI 2.3-2, the applicant considered all

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I
componIents (for the control room ventilati6ri)system) within the systems identified in LRA

Tables 2.2-1 a and 2.2-1 b, and all structures (for the control rootm ventilation system) identified

in LRA Table 2.2-3, to be within the scope of license renewal for the purpose of identifying SCs

(for the control room ventilation system) that are subject to AMR, including components in the

system considered only for 10 CFR 54.4(a)(2).

Based on its review,-the staff finds the applicaht's response to RAI 2.3-2 acceptable, because

the applicant considered all components within the control room ventilation system as identified

in LRA Tables 2.2-1 a and 2.2-1 b, and all control room ventilation system structures identified in

LRA Table'2.2-3, to be within the scope of license renewal for the purpose of identifying SCs

that are subject to AMR. Therefore, the'staff's concern described in RAI 2.3-2 is resolved.

RAI 2.3-3(a)

The staff requested that the applicant clarify whether it included the sealants used on the main

control room envelope to prevent unfiltered ifileakages within the scope of license renewal, in

accordance with 1 0 CFR 54.4(a), and subject to an AMR, in accordance with

10 CFR 54.21(a)(1).

ApDlicant's Resnonse and Staff's Evaluation:

In its response, dated May 19, 2004, the applicant stated that it included sealants or elastomers

that are used on the main control room envelope within the scope of license renewal. These

sealants are structural sealants used to minimize leakage into the control room. They are

addressed as part of structural bulk commodities and are subject to an AMR, as documented in

Section 2.4 of the LRA. Table 2.4-4 of the LRAlists the sealants under the component type

"elastomers."

Based on its review, the staff finds the applicant's response to RAI 2.3-3.a acceptable, because

the applicant considered sealants and elastomers within the control room ventilation system, as

identified in LRA Table 2.4-4, to be within the scope of license renewal and subject to an AMR.

Therefore, the staff's concern described in RAI 2.2.3-3(a) is resolved.

2.3.3.10.3 Conclusion

During its review of information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the SCs of the control room ventilation system.

Therefore, the staff concludes that the applicant has adequately identified the control room

ventilation system SCs that are within the scope of license renewal, as required by:

1 0 CFR 54.4(a), and the control room ventilation system SCs that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.3.11 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)

2.3.3.11.1 Summary of Technical Information in the Application

In Section 2.3.3.11 of the LRA, the applicant described the miscellaneous systems within the

scope of license renewal for 10 CFR 54.4(a)(2). The applicant identified the systems within the

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scope of license renewal based on the criteria of 10 CFR 54.4(a)(2) using the method described

in Section 2.1.1.2 of this SER. The applicant reviewed each mechanical system to identify

nonsafety-related systems or nonsafety-related portions of safety-related systems with the

potential for adverse spatial interaction with safety-related systems or components. This

section evaluates components subject to an AMR because of the scoping criteria of

10 CFR 54.4(a)(2). Systems within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(2) may also meet the criteria of 10 CFR 54.4(a)(1). The system description

discusses which scoping criteria are met.

The following systems, described in the referenced sections of this SER, are within the scope of

license renewal based on the criteria of 1 OCFR54.4(a)(2):

* auxiliary building ventilation (Section 2.3.3.9)

* containment spray (Section 2.3.2.2)

* chemical and volume control (Section 2.3.3.5)

* containment cooling (reactor building ventilation) (Section 2.3.2.3)

* emergency feedwater and condensate storage and transfer (Section 2.3.4.3)

* spent fuel pool (fuel pool cooling and purification) (Section 2.3.3.1)

* main feedwater (Section 2.3.4.2)

* emergency core cooling (LPSI) (Section 2.3.2.1)

* main steam (Section 2.3.4.1)

* reactor coolant (RCS and RCP system) (Section 2.3.1)

* service water (Section 2.3.3.8)

* water suppression fire protection (Section 2.3.3.2)

The following systems are within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(2) and have not been described elsewhere in the application:

* auxiliary building sump

* postaccident sampling system

* auxiliary cooling water

* plant heating

* auxiliary steam

* primary sampling

* boron management

* regenerative waste

* chemical addition

* resin transfer

* chilled water

* sampling system

* circulating water

* shutdown cooling

* component cooling water

* spent resin

* domestic water

* startup and blowdown demineralizers

* drain collection header

* steam generator secondary/blowdown

* liquid radwaste management

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turbine building sump

The descriptions below note those cases where additional scoping criteria apply and reference

the section of this SER evaluating the affected components.

Auxiliary Building Sump. The auxiliary building sump system provides drainage for equipment

to support normal plant operation. The system contains piping, valves, and pumps for

equipment and floor drains in the containment,-auxiliary building, and turbine building.

Section 2.3.2.4 of this SER evaluates the safety-related components at the containment

penetration with the containment penetrations. Therefore, the auxiliary building sump system is

also within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1).

Auxiliary Cooling Water. The auxiliary cooling water system provides cooling water to

nonsafety-related components in the auxiliary building and turbine building to support normal

plant operation.: The service water system pumps supply water to the auxiliary cooling water

system. Service water system valves provide isolation of the service water system from

auxiliary cooling water as necessary under accident conditions.

Auxiliary Steam. The auxiliary steam system provides low-pressure steam for heating and

process purposes to support normal plant operation and system testing. The system contains

valves, orifices, piping, and tubing.

Boron Management. The boron management system provides collection, handling, and

treatment of borated water to assist in the control of the boron concentration of the primary

systems. The major influent to the boron management system is reactor coolant from the

CVCS letdown as a result of feed and bleed operations for shutdown, startup, and boron

dilution over core life. The boron management system consists of boric acid tanks, holdup

tanks, pumps, and various piping and valves. The system also contains boric acid evaporators

and concentrators, but these are no longer used.

The system contains safety-related components and is therefore also within the scope of

license renewal, based on the criteria of 10 CFR 54.4(a)(1). Section 2.3.2.4 of this SER

evaluates these safety-related components with the containment penetration system.

Chemical Addition. The chemical addition system provides chemicals for various water

systems. The majority of this system is not safety related and only supports proper water.

chemistry controls for normal plant operation. The system includes chemical storage tanks,

pumps, valves, and miscellaneous components needed to store and inject chemicals. The

system includes the safety-related trisodium phosphate dodecahydrate (TSP-C) baskets in the

containment and is therefore also within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1). Section 2.4.4 of this SER evaluates the TSP-C baskets in the containment

as a structural bulk commodity.

Chilled Water. The chilled water system provides -chilled water to cooling units. This system

includes components of several closed-loop chilled water systems in different areas of the

plant, such as the containment, auxiliary building, and turbine building. Many of the system

components are nonsafety related, are not required for emergency cooling or regulated events,

and only provide cooling to support normal plant operation.

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.

The system contains safety-related components and is therefore also within the scope of

license renewal, based on the criteria of 10 CFR 54.4(a)(1). Section 2.3.2.4 of this SER

evaluates the containment penetration components, and Section 2.3.3.10 of this SER evaluates

the components in control room ventilation.

Circulating Water. The circulating water system provides cooling water to the main condenser.

One section of pipe and a valve require an AMR, based on the criteria of 10 CFR 54.4(a)(2).

These components, located in the auxiliary building, drain the circulating water system to the

service water discharge pipe.

Component Cooling Water. The component cooling water system provides closed-cycle

cooling water to nonsafety-related components to support normal plant operation. The system

consists of tanks, pumps, and associated valves and piping to the nonsafety-related equipment.

The system contains safety-related components and is therefore also within the scope of

license renewal, based on the criteria of 10 CFR 54.4(a)(1). Section 2.3.2.4 of this SER

evaluates these safety-related components with the containment penetrations system.

Domestic Water. The domestic water system provides makeup water to plant systems and

supplies water for domestic use (e.g., drinking water and sinks). The domestic water system

consists of tanks, pumps, and the associated piping and valves.

Drain Collection Header. The drain collection header system provides a drain flowpath for

numerous components in the auxiliary building. The system consists of piping and valves.

Liquid Radwaste Management. The liquid radwaste management system collects and

processes the liquid radioactive wastewater. The system includes pumps, piping, valves, and

tanks that collect, transport, and store the liquids.

Plant Heating. The plant heating system provides hot water for plant heating. It includes a

boiler, pumps, piping, valves, and area heaters.

This system includes safety-related components at the containment penetration and is

therefore also within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1).

Section 2.3.2.4 of this SER evaluates these components with the containment penetrations

system. The system contains a valve that is required for the fuel oil pressure boundary to the

fire diesel and is therefore also within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(3). The fuel oil system evaluation in Section 2.3.3.7 of this SER includes this

valve.

Postaccident Sampling System. The postaccident sampling system provides postaccident

sampling of the containment. The system includes piping, valves, coolers, pumps, sample

containers, and detectors to allow the samples to be drawn and analyzed.

Primary Sampling. The primary sampling system collects and analyzes samples from the RCS

and associated auxiliary systems. The system contains heat exchangers, pumps, tanks,

valves, piping, and other mechanical components. The sampling function is not a safety

function.

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The primary sampling system contains safety-related components and is therefore also within

the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1). Section 2.3.1 of this

SER evaluates the components in this systemrthat are part of the RCS pressure boundary.

Section 2.3.2.1 evaluates the components in this system that are part of the ECCS pressure

boundary. Section 2.3.2.4 evaluates the containment penetration components.

Regenerative Waste. The regenerative waste system processes and regenerates radioactive

wastewater. This system was originally designed with radioactive waste evaporators that are

no longer used. The system contains pumps; tanks, filters, valves, piping, and other

miscellaneous mechanical components.

Resin Transfer. The resin transfer system transfers resin for the various site demineralizers.

The system includes valves and piping.

Sampling System. The sampling system collects samples from plant systems to ensure proper

chemistry control. The sampling system consists of pumps, heat exchangers, filters, valves,

tanks, piping,-and other miscellaneous components.

The system includes safety-related piping and valves at containment penetrations that have the

safety function of maintaining the steam generator secondary pressure boundary and

containment integrity under accident conditions. The system is therefore also within the scope

of license renewal, based on the criteria of 10 CFR 54.4(a)(1). The steam generator.

secondary-side pressure boundary, as maintained by these components, is required during a

safe shutdown following a fire. The system is therefore also within the scope of license:

renewal, based on the criteria of 10 CFR 54.4(a)(3). Section 2.3.2.4 of this SER evaluates

these components with the containment penetrations system.

Shutdown Cooling. The shutdown cooling system provides cooling of the RCS without reliance

on the steam generators. The shutdown cooling system consists of heat exchangers,- valves,

tanks, piping, and other miscellaneous components.

Certain shutdown cooling components are also used for postaccident operation as part of the

LPSI system. The system is therefore also within the scope of license renewal, based on the

criteria of 10 CFR 54.4(a)(1). The system contains components that are required for safe

shutdown following a fire and is therefore also within the scope of license renewal, based on the

criteria of 10 CFR 54.4(a)(3). Section 2.3.2.1 of this SER evaluates these components with the

ECCS.

Spent Resin. The spent resin system facilitates the transfer and storage of resin from the site

demineralizers before its disposal. The system consists of tanks, pumps, filters, valves, piping,

and other miscellaneous mechanical components.

Startup and Blowdown Demineralizers. The startup and blowdown demineralizer system

removes impurities from condensate and steam generator water inventory. The blowdown

demineralizer system starts at the blowdown lines at the steam generators and includes the

blowdown heat exchangers tank, the blowdown demineralizers, blowdown pumps, and the

associated piping and valves. The majority of the system components outside of containment

are not safety related.

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The components in containment are safety related to provide a closed loop inside the

containment building for containment integrity. The system is therefore also within the scope of

license renewal, based on the criteria of 10 CFR 54.4(a)(1). The system must isolate to control

the steam generator inventory under accident conditions and during safe shutdown following a

fire when the steam generators are fed by emergency feedwater. The system is therefore also

within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(3). Section 2.3.2.4

of this SER evaluates these components with the containment penetrations.

Steam Generator Secondary/Blowdown. The steam generator secondary/blowdown system

includes instrumentation valves, tubing, and piping on the steam generator secondary side, as

well as components in the steam generator blowdown subsystem. The instrumentation piping

and valves sense the steam generator secondary side conditions and provide a main steam

system pressure boundary. The steam generator instrumentation maintains pressure boundary

integrity and indicates steam generator secondary-side conditions during safe shutdown

following a fire.

The steam generator secondary/blowdown system contains safety-related components and is

therefore also within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1).

The system contains components that are required for safe shutdown following a fire and is

therefore also within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(3).

Sections 2.3.4.1 and 2.3.4.2 of the SER include these components in the evaluations for main

steam and main feedwater, respectively.

Turbine Building Sump. The turbine building sump system provides the floor drains for

components in the turbine building and other areas, such as the emergency feedwater and

EDG rooms. The system consists of pumps, filters, valves, piping, and other miscellaneous

mechanical components.

In Table 2.3.3-11 of the LRA, the applicant listed the miscellaneous system component types

that are within the scope of license renewal and subject to an AMR, including bolting, filter

housing, heat exchanger (shell, channel head), heat exchanger (heating or cooling coil when

not enclosed in a housing), level glass gauge, orifice, piping, pump casing, tank, thermowell,

tubing, valve, and ventilation unit housing.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11, the ANO-2 UFSAR, and Engineering Report

A2-ME-2003-001 -0, Revision 1. The staff conducted its review, with support from the plant

audit and the applicant's methodology described in Section 2.3 of this SER, in accordance with

the guidance described in Section 2.3 of the SRP-LR.

In the performance of its review, the staff selected the miscellaneous system functions

described in the UFSAR, in accordance with the requirements of 10 CFR 54.4, and evaluated

the cited engineering report to confirm that the applicant did not inadvertently omit from the

scope of license renewal any components of the miscellaneous systems with intended functions

delineated under 10 CFR 54.4(a)(2). The staff then reviewed the applicant's screening

process, with the information in the LRA, the engineering report, and the screening

methodology described in Section 2.3 of this SER, to confirm that the applicant did not omit any

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passive and long-lived components of the miscellaneous systerris that should be subject to an'

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.3.11 and the engineering report, the staff identified areas in which

it needed additional information to complete its' evaluation of the'applicant's scoping and

screening results. Therefore, by letter dated May 11, 2004, the staff issued RAls, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54'4(a) and the screening criteria of

10 CFR 54.21(a)(1).

RAI 2.3.3.11-1 (a)

The staff reviewed Engineering Report A2-ME-2003-001 -0, Revision 1, Section 3.62, "Plant

Heating," and Section 3.87, 'Turbine Building Surmip," and noted that both sections list cast iron

components (i.e., valves and piping) as requiring an AMR. However, LRA Table 3.3.2-11 does

not contain an entry for cast iron valve bodies or piping for the environments cited in' the

engineering report. Therefore, the staff requested that the applicant explain why a separate

entry in LRA Table 3.3.2-11 does not exist for cast iron components, or update LRA Table

3.3.2-11 to include them.

Applicant's Response and Staff's Evaluation '

In its response dated June 10, 2004, the applicant stated that cast iron material type is included

in the general material type 'carbon steel' since the aging effect (loss of material) and AMPs

(System Walkdown Program for all components and Water Chemistry Control Program for

treated water systems) are the same for carbon steel or cast iron components in'Engineering

Report A2-ME-2003-001 -0, Revision 0. The engineering report indicates this inclusion'of cast

iron in the carbon steel material type with'the phrase "carbon steel (including cast iron)" or

"carbon steel (cast iron)" in Sections 3.62 and 3.87.' These subsections of the engineering

report identify selective leaching as an aging mechanism that will result in'the aging effect of'

loss of material for cast iron components.

Based on its review, the staff finds the'applicant's response to RAI 2.3.3.11-1 (a) acceptable,

because the aging effects for cast iron are similar to those of carbon steel in the same

environments. An evaluation performed by an NRC staff metallurgist supports this statement."

Therefore, the staff considers its concern described in RAI 2.3.3.11-1 (a) resolved.

RAI 2.3.3.11 -1 (b)

Section 2.3.3.11 of the LRA lists the component types "tank" and "filters" for the regenerative

waste system. The staff reviewed Section' 3.75 of Engineering Report A2-ME-2003-001 -0 and

found that the list of the passive mechanical c6rriponents in the regenerative waste system that

require an AMR to meet the 'criteria of 10 CFR 54.4(a)(2) does' not include tanks or filters.

Therefore, the staff requested that the applicant justify why these tanks'and filters are not

subject to an AMR, when 'the piping and valves leading to them are subject to an AMR.

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Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that, as identified in Engineering

Report A2-ME-2003-001-0, a large portion of the regenerative waste system is not used. This

system was originally designed with radioactive waste evaporators and other associated

components that are no longer used.

The applicant further stated that no tanks in the system are within the scope of license renewal,

per 10 CFR 54.4(a)(2), since the tanks that are in the system are empty or are located in areas

that cannot affect safety-related components. Two filters, as well as the piping and valves,

associated with the regenerative waste system are located in the auxiliary building and are

subject to an AMR. Section 3.75 of A2-ME-2003-001-O does not specifically identify these two

filters, but Attachment 2 of A2-ME-2003-001-0 includes them. Tables 2.3.3-11 and 3.3.2-11 of

the LRA include them as component type 'filter housing."-

Based on its review, the staff finds the applicant's response to RAI 2.3.3.11 -1 (b) acceptable,

because the filter housings are appropriately included within the scope of license renewal and

are subject to an AMR. With regard to the tanks, the applicant has verified that the tanks of

concern currently do not contain liquid or will not spatially interact with safety-related

components. As such, these tanks do not meet the criteria in 10 CFR 54.4(a)(2) and are not

within the scope of license renewal. Therefore, the staff considers its concern described in RAI

2.3.3.11 -1 (b) resolved.

RAI 2.3.3.11-1(c))

Pursuant to 10 CFR 54.21(a), applicants must identify and list in their LRAs those SCs that are

subject to an AMR. The staff identified that the LRA does not satisfy this requirement because

the applicant did not identify the mechanical components within the scope of license renewal, in

accordance with 10 CFR 54.4(a)(2), as subject to an AMR on license renewal drawings or, by

any designator or specific description, in Engineering Report A2-ME-2003-001-0. The

engineering report provides a general description on aging management of nonsafety-related

systems and components affecting safety-related systems but does not specify or identify the

components that require an AMR for each system. Therefore, the staff requested that the

applicant provide a means of specifically identifying mechanical components subject to an

AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that it considered the impacts of the

failure of nonsafety-related SSCs to be either functional or spatial. In a functional failure, the

failure of an SSC to perform its normal function impacts another safety function. In a spatial

failure, a safety function is impacted by the loss of structural or mechanical integrity of an SSC

in physical proximity to a safety-related component. Spatial failures result in the inclusion of the

most equipment. Section 2.1.1.2.2 of the LRA provides information on how and where

nonsafety-related equipment can impact safety-related equipment through spatial interaction.

The applicant also stated that, in Engineering Report A2-ME-2003-0001 -0, it reviewed all

mechanical systems at ANO-2. If a system contains components subject to an AMR in

accordance with the requirements of 10 CFR 54.4(a)(2), then the applicant listed the

component types subject to an AMR in the system section of the LRA. The applicant further

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stated that highlighted license renewal drawings identifying 10 .CFR 54.4(a)(2) components

would be of limited value to a reviewer since license renewal drawings do not provide

equipment location information. Without location information, it cannot be determined if

nonsafety-related equipment has a potential for spatial interaction, such as that from leakage or

spray, with safety-related equipment.

The applicant then described the approach implemented in Engineering Report

A2-ME-2003-0001-O to identify mechanical systems that meet the requirements of

10 CFR 54.4(a)(2) and components that are subject to an AMR for leakage and spray. First,

the applicant identified the structures at ANO-2 containing safety-related equipment. The

applicant identified the ANO-2 containment building, auxiliary building, intake structures, and

emergency diesel fuel oil storage vault as the primary seismic Class 1 structures at ANO-2

containing safety-related plant equipment. These areas contain the relevant targets (i.e.,

safety-related SSCs with the potential to be affected by failure of nonsafety-related

components). Second, if the system contains liquid or steam and has nonsafety-related

equipment in the containment building, auxiliary building, intake structures, or emergency diesel

fuel oil storage vault, then the applicant reviewed individual system components. The applicant

performed this review with the ANO-2 component database information that identifies,

component locations. The applicant reviewed liquid- or steam-filled nonsafety-related

components in the safety-related structures specified above for their potential for interaction

with safety-related equipment using equipment location information in the ANO-2 component

database and equipment layout drawings.; Initially, the applicant included all nonsafety-related

components containing liquid or steam located in the containment building, auxiliary building,

intake structure, and emergency diesel fuel storage vault as subject to an AMR unless no

safety-related equipment is in the area of the nonsafety-related component. The applicant

performed additional reviews to exclude specific nonsafety-related components where design

features, such as room separation, walls, panels, or enclosures, would protect safety-related

equipment from leakage or spray. The applicant stated that it identified nonsafety-related

components within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a)(2), to the extent necessary to assure effective management of

the effects of aging.'

However, the staff found that the applicant's response did not specifically identify which

components in the nonsafety-related systems meet the 10 CFR 54.4(a)(2) scoping criteria and

are subject to an AMR. In a followup question,,the staff asked the applicant to identify the

nonsafety-related components having either functional or spatial impacts on safety-related

components and subject to an AMR using one of the following previously accepted methods or

another equally effective method. The applicant should (1) list specific systems and specific

identifiable plant areas where all components of the listed system are within the scope of

license renewal, (2) list specific components subject to an AMR, or (3) identify components

within the scope of license renewal by highlighting them on system drawings.

Specifically, the staff requested, for certain systems with the credible potential to cause broad

spatial effects through flooding (i.e., large-diameter fire water and service water. piping), that the

applicant provide the basis for concluding that the effect of a leak from a component failure in

these systems would be limited to direct spray on nearby safety-related components.

In its response dated June 10, 2004, the applicant stated that the method for nonsafety-related

components having either functional or spatial impacts on safety-related components is very

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similar to the first method given above, in that Section 2.3.3.11 of the LRA provides all the

mechanical systems with components included for 10 CFR 54.4(a)(2). The response to RAI

2.3.3.11-1 (c)) provides the plant buildings/areas where these components are located. Section

3.0 of Engineering Report A2-ME-2003-0001-0 addresses the limited population of components

in the buildings excluded from review.

With regard to the staff's question about certain systems with the credible potential to cause

broad spatial effects through flooding, the applicant stated, in its response dated June 10, 2004,

that the engineering report identifies the fire water piping and service water system piping in

safety-related buildings that are not already reviewed as part of the system review in LRA

Sections 2.3.3.2 and 2.3.3.8, respectively, as within the scope of license renewal per

10 CFR 54.4(a)(2) and subject to an AMR. The applicant stated that the portions of the fire

water and service water systems that could cause flooding of safety-related components are

within the scope of license renewal and subject to an AMR. Section 2.3.3.11 of the LRA covers

these.

Based on its review of the applicant's June 10, 2004 response to RAI 2.3.3.11-1 (c)), followup

questions, and discussions with the applicant in a subsequent teleconference, the staff

reviewed the service water, containment spray, and CVCS mechanical systems in Engineering

Report A2-ME-2003-0001-0 to confirm that the applicant has appropriately included

components within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a)(2). On the basis of its review of these mechanical systems,

the staff did not find any omissions. The staff concluded that the applicant has appropriately

included in the LRA nonsafety-related components within the scope of license renewal and

subject to an AMR for these systems.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.11-1 (c)) and clarifying

questions acceptable, pending the AMR review of these nonsafety-related components within

the scope of license renewal and subject to an AMR, in accordance with 10 CFR 54.4(a)(2).

Since the applicant has not specifically identified components by component identification

number in its response, and the staff did not find any omissions of nonsafety-related

components subject to an AMR in accordance with 10 CFR 54.4(a)(2), the staff concluded that

the applicant defined the population of components within the scope of license renewal in

accordance with 10 CFR 54.4.(a)(2). However, the staff also concluded that the lack of

identified component identification numbers may create inconclusive staff AMR reviews of 10

CFR 54.4(a)(2) components. Therefore, the staff considers its concern described in RAI

2.3.3.11-1 (c)) and clarifying questions resolved, pending the staff's AMRs of these components.

Section 3.3.2.4.11 of this SER provides the staff's AMR reviews of these nonsafety-related

components.

2.3.3.11.3 Conclusion

During its review of the information provided in the LRA, UFSAR, engineering report, other

site documents, the license renewal drawings, and licensing basis information, the staff did not

identify any omissions or discrepancies in the applicant's scoping and screening results for the

components of the miscellaneous systems. Therefore, the staff concludes that the applicant

has adequately identified the components of the miscellaneous systems that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the miscellaneous systems that

are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.12 Other Miscellaneous Systems--

2.3.3.12.1 Summary of Technical Information in the Application

In Section 2.3.3.12 of the LRA, the applicant described other miscellaneous systems. This

section discusses various systems within the scope of license renewal with components subject

to an AMR that have been included in the mechanical system reviews of other systems or the

structural reviews. The system descriptions include discussions of the components subject to

an AMR and references to the sections containing the component evaluations. Systems

described in this section include the intake'structure (ventilation), nitrogen supply, service air,

traveling screen wash, and ventilation system.

Intake Structure (Ventilation). The intake structure (ventilation) system consists of ventilation

components in the intake structure that support fire protection and service water system

functions. The component database classifies these components as intake structure system

components, but they are evaluated with the systems supported (see Sections 2.3.3.2 and

2.3.3.8 of this SER).' Section 2.4.3 of this SER describes the intake structure itself.

The ventilation supporting the service water pumps is safety related, and therefore the intake

structure (ventilation) is within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1). The ventilation for the fire protection components is required for

compliance with Commission's regulations for fire protection (10 CFR 50.48), and the system is

therefore within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(3).

Nitrogen Supply. The nitrogen supply system provides pressurized nitrogen gas for site

components such as the safety injection tanks, the steam generator secondary, and the CVCS

charging pump pulsation dampeners and suction stabilizers. The nitrogen supply system also

provides nitrogen to safety-related electrical penetrations to prevent leakage under accident

conditions. The nitrogen system includes containment penetration components that are

required for containment isolation under accident conditions, as well as valves and piping for

supplying the nitrogen.

Sections 2.3.2.4, 2.3.3.5, and 2.3.4.1 of this SER evaluate the nitrogen supply system

components that are subject to an AMR. -i

The nitrogen supply system contains safety-related components and is therefore within the

scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1).

Service Air. The service air system provides'compressed air for service air outlets located

throughout the plant site which will be used for operation of pneumatic tools. The service air

system consists of air compressors, air receivers;-piping, and valves. The service air system

contains several safety-related containment isolation valves, evaluated in Section 2.3.2.4 of.this

SER. Section 2.3.3.1 of this SER evaluates the safety-related fuel transfer tube gasket air test

isolation valve with the spent fuel pool system. The system is within the scope of license

renewal, based on the criteria of 10 CFR 54.4(a)(1).

Traveling Screen Wash. The traveling screen wash system for ANO-2 filters water from Lake

Dardanelle before it is supplied to the service water bays. This system code includes two

traveling water screens in the ANO-2 intake structure, along with their motors, gearboxes, and

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controls and the associated ANO-2 screen wash piping and valves. Water from the ANO-1

screen wash system provides spray water to wash the ANO-2 traveling water screens as they

travel past the spray nozzles. The debris can be sluiced to trash collection baskets.

The system contains no safety-related components but is conservatively included in the scope

of license renewal to be consistent with the evaluation of the traveling screen wash system in

the ANO-1 license renewal SER. No components are subject to an AMR, as they are either

active components or do not perform an intended function. Consistent with the ANO-1 license

renewal SER, the traveling water screens are considered active devices. The supporting

structural components are reviewed as required in structural evaluations.

Ventilation System. The ventilation system provides a suitable environment for equipment and

personnel for various structures on the ANO site, including the alternate ac diesel generator

building. The system consists of blowers, heating coils, filters, dampers, ductwork, and other

miscellaneous mechanical components. The system does not include safety-related

components or perform a safety function, but the alternate ac diesel generator building

ventilation is required for the alternate ac diesel to function during SBO or for safe shutdown

following a fire. Thus, the system contains components that are required for SBO and safe

shutdown following a fire and is therefore within the scope of license renewal, based on the

criteria of 10 CFR 54.4(a)(3). Section 2.3.3.4 of this SER evaluates the alternate ac ventilation

components with the alternate ac diesel.

2.3.3.12.2 Staff Evaluation

The staff evaluated LRA Section 2.3.3.12, the UFSAR, and site documentation in its scoping

and screening review of other miscellaneous systems. The staff conducted its review, with the

support from the site visit and applicant's methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of the SRP-LR.

In the performance of the review, the staff selected system functions described in the UFSAR,

in accordance with the requirements of 10 CFR 54.4, and evaluated site documentation to

confirm that the applicant did not inadvertently omit from the scope of license renewal any

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed

those components that the applicant identified as having intended functions to confirm that the

applicant did not omit any passive and long-lived components that should be subject to an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Sedtion 2.3.3.12 and site documentation, the staff identified areas in which it

needed additional information to complete the evaluation of the applicant's scoping and

screening results. Therefore, by letter dated May 11, 2004, the staff issued RAls, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1).

RAI 2.3-1d

The staff requested that the applicant determine that the LRA has not omitted any other

miscellaneous systems' SCs that should be within the scope of license renewal, according to

10 CFR 54.4(a).

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Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), other miscellaneous systems' SCs subject to AMR are those that perform

an intended function without moving parts or a change in configuration or properties (i.e.,

passive) and that are not subject to replacement based on a qualified life or specified time

period (i.e., long-lived). Among the systems and structures within the scope of license renewal,

the applicant identified the other miscellaneous systems' SCs that are subject to an AMR, in

accordance with 10 CFR 54.21, in LRA Tables 2.2-1 a, 2.2-1 b, and 2.2-3. The applicant,

conservatively considered them to be within the scope of license renewal for the purpose of

identifying SCs that are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3-1 d acceptable, because

the applicant considered all components within the other miscellaneous systems as identified in

LRA Tables 2.2-1 a and 2.2-1 b, and all other miscellaneous systems' structures identified in

LRA Table 2.2-3, to be within the scope of license renewal for the purpose of identifying SCs

that are subject to AMR. Therefore, the staff's concern described in RAI 2.3-1 d is resolved.

RAI 2.3-2

In LRA Section 2.1.1, the applicant stated that it prepared LRA drawings to indicate

components subject to an AMR. The applicant did not indicate components for the other

miscellaneous systems that are subject to an AMR based only on the criteria of

10 CFR 54.4(a)(2) on the LRA drawings. The staff requested that the applicant determine that.

the LRA has not omitted any other miscellaneous systems' SCs that should be within the scope

of license renewal, according to 10 CFR 54.4(a).-

Applicant's Response and Staff's Evaluation

In its response, dated May 19, 2004, the applicant stated that, in accordance with

10 CFR 54.21 (a)(1), as given in the response to RAI 2.1.1-2, it considered all components for:

other miscellaneous systems within the systems identified in LRA Tables 2.2-la and 2.2-ib,

and all structures for the other miscellaneous systems' identified in LRA Table 2.2-3, to be

within the scope of license renewal for the purpose of identifying other miscellaneous systems'

SCs that are subject to AMR, including components in the system considered only in response

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

Based on its review, the staff finds the applicant's response to RAI 2.3-2 acceptable, because

the applicant considered all components within the other miscellaneous systems as identified in

LRA Tables 2.2-1 a and 2.2-1 b, and all other miscellaneous systems' structures identified in

LRA Table 2.2-3, to be within the scope of license renewal for the purpose of identifying SCs

that are subject to AMR. Therefore, the staff's concern described in RAI 2.3-2 is resolved.

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RAI 2.3.3.12-1

License renewal drawing LRA-2260 shows the ventilation for the intake structure, two

exhaust fans, shutoff dampers, and associated ducts as subject to an AMR. In UFSAR Section

9.4.6, the applicant stated that exhausted air is replaced through an opening in the roof and two

openings in louvered doors. The license renewal drawing does not highlight these openings.

and fans. The staff determined, from its review of the UFSAR, that the two fans supported by

the openings are necessary to ventilate the rooms during a design-basis accident to maintain

safe equipment operating temperatures. The staff asked the applicant to justify why the

openings which replace the exhausted air are not subject to an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that the ventilation intake openings

are subject to an AMR as part of the intake structure. Table 2.4-3 of the LRA lists them as

support for roof hatches and louvered doors. Based on its review, the staff finds the applicant's

response acceptable, because LRA Table 2.4-3 includes the ventilation intake openings within

the scope of license renewal and subject to an AMR as part of the intake structure scoping and

screening results. Therefore, the staff considers its concern described in RAI 2.3.3.12-1

resolved.

RAI 2.3.3.12-2

License renewal drawing LRA-2260 shows two intake structure exhaust fans as subject to an

AMR. The staff requested that the applicant clarify if it included the housings for these fans as

a component type in LRA Tables 2.3.3-8 and 3.3.2-8. If not, the staff asked the applicant to

update the corresponding tables to include these components.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that LRA Tables 2.3.3-8 and 3.3.2-8

include the housings for the two exhaust fans, shown on license renewal drawing LRA-2260,

as the component type "blower housing." Based on its review, the staff finds the applicant's

response acceptable, because LRA Tables 2.3.3-8 and 3.3.2-8 include the two intake structure

exhaust fans as the component type "blower housing." The two intake structure exhaust fans

are subject to an AMR. Therefore, the staff considers its concern described in RAI 2.3.3.12-2

resolved.

RAI 2.3.3.12-3

Section 2.3.3.12 of the LRA states that the nitrogen supply system contains safety-related

components and is therefore within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1). During the December 16, 2003, teleconference between the staff and the

applicant, the applicant stated that if a system is determined to be within the scope of license

renewal, then it conservatively assumed that all components in that system are within the scope

of license renewal. The staff identified portions of the nitrogen supply system that are

highlighted on license renewal drawings LRA-2232, LRA-2231, and LRA-2206.

However, license renewal drawing LRA-2239 does not highlight the supply lines to the above

nitrogen supply system piping; only portions associated with the containment penetrations are

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highlighted. The staff asked the applicant to explain why the portions of the nitrogen supply -

system, in particular the supply lines discussed above as shown- on drawing LRA-2239, are

not subject to an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that the nitrogen supply system is

within the scope of license renewal, based on the criteria of 10 CFR 54.4(a)(1), because it

contains safety-related components. However, only those passive and long-lived components

that perform a license renewal intended function are subject to an AMR, as stated in

10 CFR 54.21 (a). Passive and long-lived components in the containment penetration portion of

the supply lines (highlighted on LRA- 2239) perform a containment isolation function and are

therefore subject to an AMR. Passive and long-lived nitrogen supply system components, such

as those highlighted on license renewal drawings LRA-2232, LRA-2231, and LRA-2206,

perform a system-level pressure boundary function for a system with a license renewal

intended function and are therefore subject to an AMR. The remainder of the nitrogen supply

system (including the nonhighlighted supply lines on drawing LRA-2239) does not perform a

license renewal intended function. Thus, passive and long-lived components in the

nonhighlighted nitrogen supply lines are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.12-3 acceptable,

because the portions of the nitrogen system in question do not perform an intended function per

10 CFR 54.4(a), and therefore are not in scope and subject to an AMR. Therefore, the staff

considers its concern described in RAI 2.3.3.12-3 resolved.

On November 1 through 5 and 15 through 19,2004, the NRC staff performed an AMP

inspection at ANO-2 during which the staff reviewed the procedures for implementing AMP's for

mechanical components. During the inspection, the NRC staff noted that some component

types added to the scope of license renewal as result of the applicant's response to RAI 2.1-4,

part a were not included in the appropriate tables in LRA Sections 2.3 and 3.3. During a followup inspection on February 16 and 17, 2005,-the inspectors confirmed that the applicant had

identified the components that were omitted from the tables. These components were listed in

a supplemental table and included in a letter from the applicant dated February 28, 2005. The

aging management reviews for these components are included in Section 3 of this SER. The

issue associated with this inspection item is closed.

2.3.3.12.3 Conclusion

During its review of the information provided in the LRA, UFSAR, site documentation, the

license renewal drawings, and licensing basis information, the staff did not identify any

omissions or discrepancies in the applicant's scoping and screening results for the components

of the other miscellaneous systems addressed in the LRA. Therefore, the staff concludes that

the applicant has adequately identified the components of the other miscellaneous systems that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components of the other miscellaneous systems that are subject

to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.4 Steam and Power Conversion Systems

In Section 2.3.4 of the LRA, the applicant identified the SCs of the steam and power conversion

systems that are subject to an AMR for license renewal. The applicant described the following

steam and power conversion systems:

* main steam

* main feedwater

* emergency feedwater

2.3.4.1 Main Steam

2.3.4.1.1 Summary of Technical Information in the Application

In Section 2.3.4.1 of the LRA, the applicant described the main steam system. The main steam

system conveys steam from the steam generators to the turbine generator and to other

auxiliary equipment for power generation. The main steam system supplies steam to the highpressure turbine and to the moisture separator reheaters during normal plant operation, to the

turbine gland seals during low loads, and to the main feedwater pump steam turbine drivers

during low loads or whenever low-pressure steam is not sufficient. The main steam system

provides steam to the supply header for the turbine-driven emergency feedwater pump turbine

that is required for accident conditions and for safe shutdown following a fire.

The main steam system forms part of the closed system inside containment for containment

integrity under accident conditions. This system contains nonsafety-related components,

evaluated in Section 2.3.3.11 of this SER, whose failure could impact safety-related

components.

This system provides main steam pressure control following a fire to control the cooldown of the

RCS. The local control of the atmospheric dump valve or its upstream isolation valve will

control the steaming rate and the plant cooldown rate for safe shutdown.

Certain components in the nitrogen supply system are evaluated with the main steam system.

These components are associated with the nitrogen supply to the secondary side of the steam

generator. Certain emergency feedwater components in the main steam supply to the

emergency feedwater turbine are also evaluated with the main steam system, as are

components from the steam generator secondary/blowdown system.

The main steam system is within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1-3).

In Table 2.3.4-1 of the LRA, the applicant identified the main steam system component types

that are within the scope of license renewal and subject to an AMR, including bolting, expansion

joint, orifice, piping, steam trap, thermowell, tubing, and valve.

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2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1, ANO-2 UFSAR Sections 10.3,15.1.14, and 3.6.4.1,

and site documentation in its scoping and screening review of the main steam system. The

staff conducted its review, with support from the plant audit and the applicant's methodology

described in Section 2.3 of this SER, in accordance with the guidance described in Section 2.3

of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documents to confirm

that the applicant did not inadvertently omit from the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews

those components for the main steam system in Section 2.3.3.11 of this SER. The staff then

reviewed those components that the applicant identified as having an intended function to ;

confirm that the applicant did not omit any passive and long-lived components that should be

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

In reviewing LRA Section 2.3.4.1 and site documentation, the staff identified an area in which it

needed additional information to complete its evaluation of the applicant's scoping and

screening results. Therefore, by letter dated May 11, 2004, the staff issued an RAI, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1).

RAI 2.3.4.1 -1

Section 10.2.3.1 of the UFSAR states that a venturi flow element and a flow restrictor are

installed in each main steamline and steam generator outlet nozzle, respectively, to limit the

blowdown rate following a main steamline break. Table 2.3.4-1 of the LRA lists the component

type "orifice," which would include the venturi flow element and the flow restrictor, as subject to

an AMR. However, the table lists "pressure boundary" as the only intended function of the

component type "orifice" and neglects to list "flow control" as an intended function. The staff2

asked the applicant to justify not listing flow control as an intended function of the component

type "orifice" in the table or revise the table accordingly.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that, as described in the third

paragraph of UFSAR Section 10.3.2.1, "The venturi flow element can also function to limit the

blowdown rate following a postulated pipe rupture in the main steam line; however, the main

steam flow restrictors installed in the steam generator outlet nozzles are credited with

performing this function." The applicant further stated that, because the UFSAR states that the

venturi (orifice) is not credited with the function of flow control, LRA Table 2.3.4-1 does not list

the intended function of flow control. -Table 2.3.1-5 of the LRA includes the main steamf low

restrictors in the steam generator in the RCS as flow-limiting inserts with the intended functions

of flow control and pressure boundary.

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Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-1 acceptable,

because the flow control function of the flow restrictors is included in the AMR for the steam

generators. Since the applicant did not credit the venturi in the accident analysis, LRA Table

2.3.4-1 need not include the intended function of flow control for the venturi component.

Therefore, the staff considers its concern described in RAI 2.3.4.1-1 resolved.

2.3.4.1.3 Conclusion

During its review of the information provided in the LRA, UFSAR, site documentation, the

license renewal drawings, and the licensing basis information, the staff did not identify any

omissions or discrepancies in the applicant's scoping and screening results for the components

of the main steam system. Therefore, the staff concludes that the applicant has adequately

identified the components of the main steam system that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

components of the main steam system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.4.2 Main Feedwater

2.3.4.2.1 Summary of Technical Information in the Application

In Section 2.3.4.2 of the LRA, the applicant described the main feedwater system, which

provides feedwater to the steam generators to support normal operations. The main feedwater

system provides a flowpath for emergency feedwater to the steam generators and isolates

feedwater flow to the steam generators during a main steam or feedwater line break event or

containment over pressurization. The system comprises two interconnected trains, consisting

of steam-driven main feedwater pumps, pump recirculation valves, feedwater flow control

valves, feedwater heaters, feedwater block valves, vent and drain valves, and associated piping

and tubing.

The main feedwater system is largely nonsafety related but has a safety-related portion that

provides isolation to the steam generators following a main steam or feedwater line break or

containment building overpressure condition. The safety-related portion of the system is the

piping and related equipment, starting with the main feedwater block valve closest to

containment and continuing to the steam generators. The second block valve (outboard) on

each train is also safety related, but the piping and valves between the two block valves are not

safety related.

This system contains nonsafety-related components, evaluated in Section 2.3.3.11 of this SER,

whose failure could impact safety-related components. The main feedwater block valves,

piping, and steam generators, which are credited in conjunction with main steam for RCS decay

heat removal for safe shutdown after a fire, provide the pressure boundary integrity for

feedwater. These components perform a function that demonstrates compliance with the

Commission's regulations for fire protection (10 CFR 50.48).

Steam generator water-level monitoring components, which are classified as part of the steam

generator secondarylblowdown system, are evaluated with the main feedwater system. These

components provide monitoring of the steam generator water-level for power operations and

safe plant shutdown.

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The main feedwater system is within the scope of license renewal, based on the criteria of

10 CFR 54.4(a)(1-3).

In Table 2.3.4-2 of the LRA, the applicant identified the main feedwater system component

types that are within the scope of license renewal and subject to an AMR, including bolting,

piping, tubing, and valve.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, ANO-2 UFSAR Sections 10.4.7, 15.1.14, and 3.6.4.1,

and site documentation in its scoping and screening evaluation of the main feedwater system.

The staff conducted its review, with support from the plant audit and the applicant's

methodology described in Section 2.3 of this SER, in accordance with the guidance described

in Section 2.3 of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and reviewed site documents to determine

that the applicant did not inadvertently omit from'the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews

those components for the main feedwater system in Section 2.3.3.11 of this SER. The staff

then reviewed those components that the applicant identified as having an intended function .to

determine that the applicant did not omit any passive and long-lived components that should be

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

The main feedwater system is largely nonsafety related, except for a portion of piping between

the steam generators and the outboard containment isolation valves. The license renewal

drawings highlight the safety-related portion of the main feedwater piping within the scope of

license renewal and subject to an AMR. As'stated in the UFSAR, the portions of the .

nonsafety-related piping have been analyzed to withstand design-basis earthquake loads.

Although the applicant has not highlighted license renewal drawings nor identified, in the LRA,

the specific main feedwater components within the scope of license renewal meeting the criteria

of 10 CFR 54.4(a)(2), the applicant stated in LRA Section 2.1.1.2.2 that if a HELB analysis

assumes that nonsafety-related piping does not fail or assumes failure only at specific

locations, then that piping system is within the scope of license renewal per 10 CFR 54.4(a)(2)

and subject to an AMR, in order to provide confirmation that those assumptions remain valid

through the period of extended operation. Section 2.1.1.2.2 of the LRA also states that

nonsafety-related systems and nonsafety-related portions of safety-related systems containing

steam or liquid that are near safety-related equipment are considered in scope and subject to

an AMR, per 10 CFR 54.4(a)(2). Therefore, the staff considers that the LRA properly

addresses nonsafety-related components.

In its review of LRA Section 2.3.4.2 and site documentation, the staff identified an area in which

it needed additional information to complete'its evaluation of the applicant's scoping and

screening results. Therefore, by letter dated May 11, 2004, the staff issued an RAI, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1).

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RAI 2.3.4.2-1

Section 2.3.4.2 of the LRA states that the second block valve (outboard) on each train of the

main feedwater system is safety related. The staff identified that license renewal drawing

LRA-2206 does not highlight the outboard block valves as subject to an AMR. In UFSAR

Section 15.1.14, the applicant identified these valves (as the backup main feedwater isolation

valves) as receiving an isolation signal to close during steamline breaks (either via the main

steam isolation signal or the containment spray actuation signal). The UFSAR Chapter 15

analyses credit these valves. The staff asked the applicant to justify its exclusion of the

outboard second feedwater block valve from the scope of license renewal, and of its valve body

from an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that the second (outboard) block

valves are within the scope of license renewal (as part of the main feedwater system) but are

not subject to an AMR as they perform their intended function with moving parts. The applicant

further stated that the only intended function of these outboard block valves is to provide

feedwater isolation, which relies on the closure of the valve disc by the motor operator. The

loss of pressure boundary in this portion of the system would not prevent satisfactory isolation

of feedwater flow to the steam generators.

Based on its review of the applicant's response and a teleconference with the applicant, the

staff asked the applicant to clarify its response to RAI 2.3.4.2-1. The staff stated that since the

valve is safety related, the valve body should be subject to an AMR by definition, according to

10 CFR 54.4(a)(1). The staff asked the applicant to specifically discuss and cite the process

used to screen out the outboard block valves in accordance with 10 CFR 54.21 (a)(2).

By letter dated July 22, 2004, the applicant revised its response to RAI 2.3.4.2-1 to include the

statement, "These valves perform their function with moving parts, and in accordance with

10 CFR 54.21 (a)(1)(i), are not subject to aging management review."

Based on its review, the staff finds the applicant's revised response to RAI 2.3.4.2-1

unacceptable, because the intended function of the outboard block valves (to provide

satisfactory isolation of feedwater flow to the steam generators) does require the integrity of the

valve. The 10 CFR Part 54 SOC (September 29, 1995) states the following:

However, pressure-retaining boundaries (e.g., pump casings, valve bodies, fluid

system piping) and structural supports (e.g., diesel generator structural supports)

that are necessary for the structure or component to perform its intended

function meet the description of passive, and will be subject to an aging

management review.

Furthermore, the main feedwater block valves provide pressure boundary integrity for the

feedwater system following a fire and satisfy the criteria in 10 CFR 54.4(a)(3). The applicant

did not identify this function. Therefore, pressure boundary integrity of the outboard valve is

required. As such, the valves (bodies) in question should be subject to an AMR. The staff

asked the applicant to justify its exclusion of the outboard valve from an AMR.

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In a letter dated September 10, 2004, the applicant stated that these valves are within the

scope of license renewal and subject to an AMR as part of the nonsafety-related piping and

supports up to and including the first equivalent anchor beyond the safety-related interface.

The staff found the applicant's response acceptable because the applicant has included these

outboard valves in scope and subject to an AMR for license renewal to meet 10 CFR 54.4(a)(2)

criterion. Therefore, the issues associated with RAI 2.3.4.2-1 are resolved.

2.3.4.2.3 Conclusion

During its review of the information provided in the LRA, UFSAR, site documentation, the

license renewal drawings, and licensing basis information, the staff did not identify any

omissions or discrepancies in the applicant's scoping and screening results for the components

of the main feedwater system. Therefore, the staff concludes that the applicant has adequately

identified the components of the main feedwater system that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

components of the main feedwater system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.4.3 Emergency Feedwater

2.3.4.3.1 Summary of Technical Information in the Application

In Section 2.3.4.3 of the LRA, the applicant described the emergency feedwater system. The

emergency feedwater system provides a safety-related source of feedwater to the steam

generators when main feedwater is not available. The system is the safety-related source of

feedwater for cooling during design-basis events and is credited with operation for safe

shutdown following a fire.

The emergency fgedwater system consists of two safety-related pumps (one turbine-driven and

one motor-driven), a third nonsafety-related auxiliary feedwater pump, and two independent

feedwater trains, each capable of supplying feedwater to either of the two steam generators.

The condensate storage tanks, backed up by the safety-related service water system, supply

the emergency feedwater system.

The evaluation of the emergency feedwater system includes the condensate storage and

transfer system. The condensate storage and transfer system consists of two condensate

storage tanks, two condensate transfer pumps, and associated piping, controls, and

instrumentation. The safety-grade condensate storage tank is connected to the Unit 2

emergency feedwater system as an available source of emergency feedwater. Locked, closed,

double isolation valves isolate it from the system.

This system contains nonsafety-related components,- evaluated in Section 2.3.3.11 of this SER,

whose failure could impact safety-related components. The emergency feedwater system is

required for compliance with the Commission's regulations for fire protection (10 CFR 50.48).

Section 2.3.3.8 of this SER evaluates the emergency feedwater suction supply valves from the

service water system with the service water system because of the raw water environment

internal to these valves. Section 2.3.4.1 evaluates certain emergency feedwater components in

the main steam supply to the emergency feedwater turbine with the main steam system. The

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emergency feedwater system is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(1-3).

In Table 2.3.4-3 of the LRA, the applicant identified the emergency feedwater system

component types that are within the scope of license renewal and subject to an AMR, including

bearing housing, bolting, equalizer pipe, filter housing, governor housing, heat exchanger

(tubes), heat exchanger (tubesheet), heater housing, orifice, piping, pump casing, servo

housing, sight glass, sight glass (housing), steam trap, tank, thermowell, tubing, turbine casing,

and valve.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3, ANO-2 UFSAR Sections 9.2.6, 10.4.9, 15.1.14, and

3.6.4.1, and site documentation in its scoping and screening review of the emergency

feedwater system. The staff conducted its review, with support from the plant audit and the

applicant's methodology described in Section 2.3 of this SER, in accordance with the guidance

described in Section 2.3 of the SRP-LR.

In the performance of its review, the staff selected system functions described in the UFSAR, in

accordance with the requirements of 10 CFR 54.4, and evaluated site documents to determine

that the applicant did not inadvertently omit from the scope of license renewal any components

with intended functions delineated under 10 CFR 54.4(a). In LRA Section 2.3.3.11, the

applicant separately compiled scoping and screening results for all components with intended

functions that are within the scope of license renewal, per 10 CFR 54.4(a)(2). The staff reviews

those components for the emergency feedwater system in Section 2.3.3.11 of this SER. The

staff then reviewed those components that the applicant identified as having an intended

function to determine that the applicant did not omit any passive and long-lived components

that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.4.3 and site documentation, the staff identified areas in which it

needed additional information to complete its evaluation of the applicant's scoping and

screening results. Therefore, by letter dated May 11, 2004, the staff issued RAls, described

below, to the applicant concerning the specific issues to determine whether the applicant has

properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of

10 CFR 54.21 (a)(1).

RAI 2.3.4.3-1

License renewal drawing LRA-2204 does not show the nonsafety-related auxiliary feedwater

pump and its auxiliaries as subject to an AMR. In UFSAR Section 10.4.9.2, the applicant stated

that the auxiliary feedwater pump provides feedwater to the steam generators when both

safety-related emergency feedwater pumps are not available. In UFSAR Section 3.6.4.1.5.2,

the applicant stated that a HELB is postulated in the common 4-in. steamline from both the

steam generators at valve 2CV-0340-2 (license renewal drawing LRA-2202). The staff noted

that, as a result of a postulated HELB, the turbine driven emergency feedwater pump would not

be available to supply feedwater to the steam generators. In UFSAR Section 3.6, the applicant

stated that a single failure of the remaining emergency feedwater pump would require the

auxiliary feedwater pump to provide feedwater to the steam generators to bring the plant to

safe-shutdown conditions.

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However, the staff noted that UFSAR Section 3.6 does not explain how this postulated break

would achieve plant safe shutdown. The staff als6 noted that, if the auxiliary feedwater pump is

used to mitigate the consequences of a postulated HELB in the UFSAR, then the auxiliary

feedwater pump should be within the scope of license renewal to meet the criteria of

10 CFR 54.4(a)(2). The staff asked the applicant to justify the exclusion of the auxiliary

feedwater pump and its auxiliaries from an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that UFSAR Section 3.6.4.1.5.2 notes

that a break in the 4-in. steamline to the emergency feedwater pump driver will not require

safety system actuation since the blowdown in the line is within the makeup of the main

feedwater pumps to the steam generators. Isolation valves are available in the lines from the

individual steam generators to isolate a break in the common steamline. The auxiliary

feedwater pump and its auxiliaries are not subject to an AMR since the auxiliary feedwater.

pump and its auxiliaries have no intended functions that support the functions in the scoping

criteria of 10 CFR 54.4(a)(1-3).

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-1 acceptable,

because if the safety system actuation would not occur, there would be no need to assume a

plant trip and postulate the failure of the remaining emergency feedwater pump. The plant

could be shut down using nonsafety-related systems. Therefore, the staff considers its concern

described in RAI 2.3.4.3-1 resolved.

RAI 2.3.4.3-2

License renewal drawing LRA-2204 shows only a portion of the minimum recirculation lines

(upstream of valves 2EFW1OA and 2EFW1OB) as subject to an AMR. These valves are

throttling valves, which do not necessarily provide an adequate pressure boundary function.

The minimum recirculation piping extends beyond this drawing to another drawing, -2229,

which the applicant did not provide. Failure of the downstream piping could result in a loss of

pressure boundary intended function. The staff asked the applicant to provide drawing -2229

so that the staff can determine if any passive failures downstream could affect the intended

function of the emergency feedwater system. The staff stated that, if passive failures (e.g.,

piping or valve failures) downstream could affect the intended function of the emergency

feedwater system, then the applicant should include these components within the scope of

license renewal and as subject to an AMR.

Applicant's Response and Staff's Evaluation

In its response dated June 10, 2004, the applicant stated that each minimum recirculation line

contains an orifice and globe valve. The orifices allow the minimum required recirculation flow

for the pumps while ensuring that sufficient flow is provided to the steam generators, as

required for design-basis events. Thus, piping and components downstream of the orifices and

globe valves are not required to maintain pressure boundary for the steam generators to

receive sufficient flow for design-basis events, and they do not have an intended function based

on the criteria of 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3).

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Passive components in the minimum recirculation line downstream of 2EFW1OA and 2EFW1OB

do have a pressure boundary intended function for 10 CFR 54.4(a)(2). In accordance with LRA

Section 2.1.1, the license renewal drawings do not indicate components subject to an AMR

based only on the criteria of 10 CFR 54.4(a)(2). Table 3.3.2-11 of the LRA lists the

nonsafety-related portions of the emergency feedwater system that are subject to an AMR

based on the criteria of 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant's response acceptable, because the applicant

has evaluated the nonsafety-related piping for potential spatial interaction with safety-related

SSCs, as addressed in Section 2.3.3.11 of this SER. Therefore, the staff considers its concern

described in RAI 2.3.4.3-2 resolved.

2.3.4.3.3 Conclusion

During its review of the information provided in the LRA, UFSAR, site documentation, the

license renewal drawings, and licensing basis information, the staff did not identify any

omissions or discrepancies in the applicant's scoping and screening results for the components

of the emergency feedwater system. Therefore, the staff concludes that the applicant has

adequately identified the components of the emergency feedwater system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the emergency feedwater system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

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2.4 Scoping and Screening Results-Structures

Pursuant to 10 CFR 54.21 (a)(1), an applicant must identify and list SCs subject to an AMR.

These'are passive, long-lived SCs that are within the scope of license'renewal. To determine

that the applicant has properly implemented its 'methodology, the staff focuses its review on the

implementation results. Such a focus-allows the staff to confirm that the applicant has not

omitted any structural components that are subject to an AMR. If the review identifies no

omission, the staff has a basis to find that therapplicrnt has identified the structural components

that are' suibject to an AMR. -

This SER section addresses the applicant's scoping and screening results for structures. Table

2.2-3 of the LRA identifies the following structures as within the scope of license renewal:

* containment and containment internals (LRA Section 2.4.1)

- containment building

- polar crane

* auxiliary building, turbine building, arid yard structures (LRA Section 2.4.2)

- alternate ac diesel generator building

- auxiliary building

- -condensate storage tank T-41 B foundation and pipe trenches - electrical manholes

- emergency diesel fuel oil storage tank vault - fuel handling/refueling machines

- fuel oil storage tank (T-25)'fo'undation

- postaccident sampling system building

- RWT (2T3) foundation

- switchyard/transformer yard

- turbine building

* intake structure and emergency cooling pond (LRA Section 2.4.3)

- emergency cooling pond - ; -:

- intake canal

- intake structure

* bulk commodities (LRA Section 2.4.4) ''

-' fire fighting equipment'hosefreels'

- pipe hangers-plant systems'

Sections 2.4.1, 2.4.2, 2.4.3, and 2.4.4 and Tables 2:4-1, 2.4-2, 2.4-3, and 2.4-4 of the LRA

provide detailed lists of structures and itructural components included in each of these four

groups. - :.- . .

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Table 2.2-4 of the LRA identifies the ANO-2 structures that the applicant has determined are

not within the scope of license renewal. In reviewing LRA Table 2.2-4, the staff identified

several areas in which it needed additional information to complete its evaluation of the

applicant's scoping results. Therefore, by letter dated April 14, 2004, the staff issued RAI 2.4-1,

given below, to the applicant concerning the specific issues to determine whether the applicant

has properly applied the scoping criteria of 10 CFR 54.4(a):

(a) LRA Table 2.2-4 identifies structures that are not within the scope of license

renewal. It is not obvious to the staff that all of the listed structures serve no

intended function. Please provide a description of the discharge canal and the

miscellaneous tank foundations, and the technical basis for the determination

that they are not within the scope of license renewal.

(b) Verify that seismic 11/l considerations are not applicable to any of the structures

listed in LRA Table 2.2-4 (e.g., cooling tower).

(c) In addition, while the staff acknowledges that the tendon access gallery does not

serve an intended function in the strictest interpretation of the License Renewal

Rule, there is significant industry operating experience related to flooding and

corrosive environments in the tendon access gallery that have contributed to

degradation of the tendon anchorage components and surrounding concrete.

Management of the condition of the tendon access gallery is a preventive step to

minimize aging effects for the prestressing system. The applicant is requested

to submit its plant-specific operating/aging experience related to (1) flooding and

corrosive environments in the tendon access gallery, and (2) degradation of the

prestressing system components (both steel and concrete) in the tendon access

gallery, and based on the ANO-2 specific tendon gallery operating/aging

experience, discuss ANO-2's basis for not including the tendon gallery structure

within the AMR scope pursuant to 10 CFR 54.4(a)(2).

The following is the applicant's response to RAI 2.4-1, dated May 19, 2004:

(a) The discharge canal is an earthen structure with the primary function of

discharging the ANO-1 condenser cooling water to the lake. As stated in

ANO-2 Safety Analysis Report (SAR) Section 9.2.1.2.3.7, "Under

accident conditions the service water system (SWS) discharge is

automatically changed to the emergency cooling pond (ECP) upon the

initiation of a safety injection actuation signal (SIAS) or main steam

isolation signal (MSIS)." The discharge canal is not relied on as a

discharge path for the service water system. Failure of discharge canal

will not prevent accomplishment of required safety functions; therefore,

the discharge canal has no intended function.

Miscellaneous tank foundations are reinforced concrete foundations for

miscellaneous, nonsafety related tanks. Since the tanks have no

intended functions, the foundations supporting them likewise have no

intended functions. Examples of miscellaneous tanks are raw water

holdup tank and concentrator bottoms tank. The raw water holdup tank

holds water supplied from the Russellville city water system. It supplies

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the domestic water system that does not serve a safety-related function

and is not required for safe shutdown of the plant. The concentrator

bottoms tank is no longer in service. 'Neither of these examples are tanks

with the potential for failures that could prevent the satisfactory

- accomplishment of safety functions.' The foundations supporting an

intended function are provided in Table 2.2-3 of the 'LRA.

(b) As part of LRA process, the structures (e.g., cooling tower) listed in LRA

Table 2.2-4 have been reviewed for 11/l considerations. Those structures

'required to be seismically qualified for 11/l considerations have been

included in the scope of license renewal. None of the structures listed in

LRA Table 2.2-4 are a concern for seismic I1/l considerations.

(c) Prestressing system components in the tendon access gallery are

protected by end caps as appropriate. ANO-2 operating experience

indicates no significant problems with prestressing system components

due to flooding or corrosive environments in the tendon access gallery.

The ANO-2 containment building 20-year tendon surveillance and :

concrete surface'inspection indicated no abnormal degradation of the,

building or the post tensioning'system. The gallery is open to the

auxiliary building. Tendon access gallery ventilation fans operate in

conjunction with the auxiliary building ventilation system so the

environment is essentially the samras'the auxiliary building environment.

Since the tendon anchorages are in the overhead of the gallery, minor

water inleakage has no effect on the lower~tendon anchorage

components and surrounding concrete. Neither significant levels of

contaminants nor excessive humidity have been noted in the tendon

access gallery.

'The tendon access gallery provides no structural support to the reactor

building.; Since the tendon access gallery serves no license renewal

intended function, it is not within the scope of license renewal and

therefore, not subject to an aging management review.

Based on its review,'the staff finds the applicant's response to RAI 2.4-1 parts (a), (b), and (c))

acceptable, because the information submitted is sufficient to address the staff's concern. The

applicant has provided in part (a) an adequate description and technical basis for its

determination that the discharge canal and the miscellaneous tank foundations are not within

the scope of license renewal. The applicant has verified in part (b) that none of the structures

listed in LRA Table 2.2-4 are a concern for seismic Category Il/1 considerations. The applicant

has submitted in part (c)) a sufficient description of plant-specific operating/aging experience

related to environmental degradation of the'tendon access gallery and its prestressing system

components. The tendon access gallery is ventilated and has not experienced any significant

degradation that could potentially compromise the prestressing system components. The staff

concludes that there is not a sufficient technical basis to include the tendon gallery structure

within the license renewal scope, pursuant to 10 CFR 54.4(a)(2). Therefore, the staff considers

its concern described'in RAI 2.4-1 parts (a), (b), and (c)) resolved.

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Load-handling systems have components that are both mechanical and structural in nature.

The structural components are passive and long-lived. If a specific load-handling system

serves an intended function, then it is subject to an AMR. To ensure a complete understanding

of the ANO-2 scoping and screening for load-handling systems, the staff needed additional

information. Therefore, by letter dated April 14, 2004, the staff issued RAI 2.4-3, given below,

to the applicant concerning the specific issues to determine whether the applicant has properly

applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1):

Please clarify the complete scope of load handling systems included in the ANO2 LR scope. LRA Subsections 2.4.1, 2.4.2, 2.4.3 and 2.4.4 all make reference to

one or more components of various load handling systems. In addition, LRA

Section 2.1.1.2.2 states "The overhead-handling systems, whose structural

failure could result in damage to any system that could prevent the

accomplishment of a safety function, meet the criteria of 1 OCFR54.4(a)(2) and

are within the scope of license renewal.' The applicant is requested to (1)

provide a listing of all load handling systems in the LR scope; (2) define the

associated intended function; (3) identify the specific components that are

subject to an AMR, for each in-scope load handling system; (4) identify the

specific row in Table 2.4-1, 2.4-2, 2.4-3, or 2.4-4 that includes each identified

component; and (5) identify the location in LRA Section 3 that contains the AMR

for each component.

The applicant's response to RAI 2.4-3, dated May 19, 2004, is given below:

(1) The load handling systems included in the ANO-2 license renewal scope

include the polar crane, fuel handling bridge, and spent fuel cranes

(includes bridges, girders, trolleys and crane rails). Also included are

monorails and their supports which meet the criteria of 1 OCFR54.4(a)(2).

(2) As shown in Tables 2.4-1, 2.4-2, and 2.4-4 of the LRA, the intended

function of cranes and crane components is either support of a

10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) function.

(3) The specific components, listed in the LRA as crane rails and support

structures associated with the crane or monorail system, includes bridge,

trolley, rails, and girders.

(4) The specific row in Table 2.4-1, 2.4-2, and 2.4-4 that includes each

identified component are as follows:

Table 2.4 1 under uPolar crane (containment)"

Table 2.4 2 under uFuel handling bridge assembly (2H3)

crane rails and girders"

Table 2.4 2 under "Spent fuel overhead cranes (L3 and

2L35)"

Table 2.4 4 under "Monorails, crane rails and girders"

(5) Line items listed above are shown in Tables 3.5.2-1, 3.5.2-2, and 3.5.2-4

of the LRA under the same component entry.

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Based on its review, the staff finds the applicant's response to RAI 2.4-3 acceptable, because

the information submitted is sufficient to address the staff's concern. The applicant has

adequately clarified (1) the complete scope of load-handling systems included in the ANO-2

license renewal scope, (2) intended functions, (3) the specific crane components subject to an

AMR, (4) the scoping and screening references in LRA Section 2.4, and (5) the AMR

references in LRA Section 3.5. The staff concludes that the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1) to theANO-2 load-handling systems. Therefore, the staff considers its concern described in RAI 2.4-

3 resolved.;

2.4.1 Staff Evaluation Methodology

The staff performed its evaluation of the information provided in the LRA in the same manner

for all SCs. Through its review, the staff sought to determine if the applicant identified the

components and supporting structures for a specific containment structure or support that

appear to meet the scoping criteria specified in the Rule as within the scope of license renewal,

in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results

to determine that all long-lived, passive components are subject to an AMR, in accordance with

10 CFR 54.21 (a)(1).

To perform its scoping evaluation, the staff reviewed the applicable LRA section and associated

component drawings, focusing its review on components that the applicant did not identify as

within the scope of license renewal. The staff reviewed relevant licensing basis documents,

including the UFSAR, for each SC to determine if the applicant had omitted system components

with intended functions delineated under 10 CFR 54.4(a) from the scope of license renewal.

The staff also reviewed the licensing basis documents to determine if the LRA specifies all

intended functions delineated under 10 CFR 54.4(a). If it identified omissions, the staff

requested additional information to resolve the discrepancy.

Once the staff completed its review of the scoping results, it evaluated the applicant's screening

results. For those SCs with intended functions, the staff sought to determine if they perform

their functions with moving parts or a change in configuration or properties, or if they are

subject to replacement based on a qualified life or specified time period,, as described in

10 CFR 54.21 (a)(1). For those that do not meet either of these criteria, the staff sought to

confirm that these SCs are subject to an AMR, as required by 10 CFR 54.21 (a)(1). If it

identified discrepancies, the staff requested additional information to resolve them.

2.4.2 Containment and Containment Internals

In Section 2.4.1 of the LRA, the applicant described the containment and containment internals.

2.4.2.1 Summary of Technical Information in the Application

The ANO-2 containment is a seismic Category 1, fully continuous, reinforced prestressed

concrete cylindrical structure with a shallow dome roof and a mat foundation slab.. The

containment completely encloses the containment internals, the reactor vessel, and the RCS

along with other vital electrical, mechanical, instrumentation, and 'structural components. The

containment consists of (1) a flat circular base slab, (2) a right circular cylinder, and (3) a

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sphere-torus dome. It is constructed of reinforced concrete, prestressed by posttensioned

tendons in the cylinder and the dome.

The containment houses the containment internal structures. The internal structures consist of

the primary shield, secondary shield, refueling canal, removable missile shield above the

reactor vessel, floor slabs, gratings and platforms, and equipment supports. Structures

associated with the containment internals comprise structural members such as beams, girders,

joists, columns, base plates, bearing plates, bracing, splice assemblies, connections, and other

related steel items. The major structural steel components consist of the upper steam

generator and RCP restraints, lower steam generator support (which includes steam generator

support steel), reactor support, and pressurizer support steel.

The containment structure limits the release of radioactive fission products following an

accident to reduce the dose to the public and the control room operators. The containment

structure also provides physical support for itself, the RCS, engineered safety features, and

other systems and equipment within the structure. The exterior walls and dome protect the

reactor vessel and other safety-related SSCs from missiles (internal and external) and natural

phenomena.

The applicant evaluated the following SSCs for the containment building:

* anchors/embedments/attachments for systems/components

* building foundations

* concrete beams

* containment concrete cylinder wall

* containment dome, includes coatings on roof

* containment sump structure (excluding piping, equipment, instrumentation, and controls

associated with the sump)

* doors/hatches and hatch covers

* equipment hatch

* exterior and interior concrete walls

* floor and roof slabs

* fuel handling bridge, crane rails and supports

* fuel transfer canal (excludes tube portion and flanges)

* mechanical and electrical penetrations

* missile shield walls

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personnel airlock, emergency airlock

* pipe supports, cable trays, and other equipment supports (includes whip restraints) and

conduits

* polar crane rails and crane support structures

* radiation shield walls

* reactor vessel closure head lifting rig assembly structure and miscellaneous

components

* reactor structural supports (concrete and steel)

* 'stairways, platforms, ladders, handrails, gratings, and catwalks

* steam generator structural supports (concrete and steel)

* steel floor framing, columns, and bracing

* steel beams

* structural bolting

* structural steel that supports grating and catwalks, service platforms, ladders, and stairs

(required for general access)

* structural steel members and shapes (includes steam generator, pressurizer, reactor

vessel, RCPs, and safety injection tank support steel)

* tank supports (concrete and steel)

The supports for the RCS components (the reactor vessel, RCPs, steam generators, and

pressurizer) are considered unique and are iricluded in this evaluation. The bulk commodity

evaluation addresses other component and 'piping' supports, including RCS piping supports.

In Table 2.4.1 of the LRA, the applicant identified the containment structure components types

that are within the scope of license renewal and subject to an AMR, including

anchorage/embedmentlattachments, CEDM support structure,- electrical penetrations,

equipment hatch, fuel handling bridge,' crane rails and supports, liner plate, mechanical

penetrations, personnel airlocks, polar crane (containment),, pressurizer support steel, reactor

vessel support columrin refuel maintenance support structure, steam generator support,

structural steel, sump penetrations, tendon anchorage, tendon wires, reactor vessel support

bolted connections,'various threaded fasteners, basement floor slab-(includes sump and

instrumentation tunnel), columns, other walls -hatches, dome, cylinder wall, buttress, ring girder,

foundation, subfoundation, pressurizer support foundation, primary and secondary shield walls,

reactor vessel missile shield, refuel canal, steam generator support foundation, and reactor

vessel support foundation.

! 12-99
2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and the referenced ANO-2 UFSAR Sections 3.8.1 and

3.8.3. The staff conducted its review in accordance with the guidance described in Section 2.4

of the SRP-LR.

In the performance of the review, the staff evaluated the UFSAR to determine if the applicant

failed to identify any structural or component functions of the containment and containment

internals as an intended function, in accordance with the requirements of 10 CFR 54.4(a). The

staff did not identify any omissions. The staff then verified that the passive, long-lived

components are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.1 identified an area in which it needed additional

information to complete its evaluation of the applicant's scoping results. Therefore, by letter

dated April 14, 2004, the staff issued RAI 2.4-6 (part b), given below, to the applicant

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a):

UFSAR Table 3.8-1 lists "Flued Head Penetrations" for the Containment. The

applicant is requested to (1) verify that all of the listed penetrations are within the

LR scope; and (2) if not, then provide the technical basis for any exclusions.

The applicant's response to RAI 2.4-6 (part b), dated May 19, 2004, is given below:

All containment penetrations are within the scope of license renewal and subject

to aging management review as indicated in LRA Table 2.4-1.

Based on its review, the staff finds the applicant's response to RAI 2.4-6 (part b) acceptable,

because it verifies that all containment penetrations are within the scope of license renewal and

subject to an AMR. The staff concludes that the applicant has properly applied the scoping

criteria of 10 CFR 54.4(a) to the ANO-2 containment penetrations. Therefore, the staff

considers its concern described in RAI 2.4-6 (part b) resolved.

The staff's review of the LRA Section 2.4.1 identified a second area in which it needed

additional information to complete its evaluation of the applicant's scoping results. Therefore,

by letter dated April 14, 2004, the staff issued RAI 2.4-8, given below, to the applicant

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a):

Section 2.4 of the LRA does not describe the cable feed-through assembly,

which is part of containment electrical penetrations. This assembly serves a

pressure boundary intended function. Therefore, the applicant is requested to

clarify whether the cable feed-through assembly is in scope or not. If it is in

scope, identify the applicable table number and component name in LRA Section

2.4, and the applicable AMR table number and component name in LRA Section

3.5. If it is not in scope, provide the justification for its exclusion.

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I
The applicant's response to RAI 2.4-8, dated May 19, 2004, is given below:

LRA Table 2.1-1 identifies electrical portions of electrical and instrumentation

and control penetration assemblies (e.g., electrical penetration assembly cables

and connections) as an electrical commodity group that serves an intended

function. The cable feed-through assemblies are part of the penetration

assemblies and are, therefore, in scope for license renewal. As described in

LRA Section 2.1.2.3.32, most of the electrical penetration assemblies (including

the cable feed-through assemblies) are included in the Environmental

Qualification (EQ) Program.

Under the EQ Program, the electrical penetrations, including the cable feedthrough assemblies, are subject to replacement based on a qualified life and

thus, in accordance with 10 CFR 54.21 (a)(1)(ii), are not subject to aging

management review.

The non-EQ electrical penetrations-are subject to an aging management review.,

The electrical portions of the non-EQ electrical and l&C penetration assemblies

are included in the electrical scoping review. The structural portions of the

electrical penetrations providing pressure boundary (essentially leak-tight

radiological control barrier) are included in the structural review.

Although the EQ electrical penetrations are not subject to aging management

review, all electrical penetrations (EQ and non-EQ) are tested in accordance with

the requirements of 10CFR50 Appendix J. The structural components of the

electrical penetrations (EQ and non-EQ) were included in the containment and

containment internals aging management review as "mechanical and electrical

penetrations" listed in LRA Tables 2.4-1 -and 3.5.2-1, on pages 2.4-1 0 and 3.5-25

through 3.5-26. - -.

The staff did not find the applicant's response to RAI 2.4-8 completely acceptable, because it is

not clear from the response that the applicant credited Type B local leak rate testing, in

accordance with the requirements of Appendix J to 10 CFR Part 50, to manage the

leaktightness of the cable feed-through assembly. In a meeting on July 20, 2004, the staff

asked the applicant to clarify if it credited Type B local leak rate testing, in accordance with the

requirements of Appendix J to 10 CFR Part 50, to manage the leaktightness of the cable feedthrough assembly. !

The applicant's clarification to its response to RAI 2.4-8, dated July 22, 2004, is given below:

Leak tightness of electrical penetrations is tested in accordance with the

requirements of 10 CFR 50 Appendix J as indicated in LRA table 3.5.2-1. The

effects of aging on resilient seals of electrical penetration assemblies are

managed by Type B testing performed as required by Appendix J. This includes

resilient seals associated with the cable feed through assemblies. Line item

3.5.1-6 of Table 3.5.1 applies to resilient seals associated with cable feedthrough assemblies of the electrical penetrations.

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Based on its review, the staff finds the applicant's response to RAI 2.4-8 acceptable, because it

verifies that the applicant credited Type B local leak rate testing, in accordance with the

requirements of Appendix J to 10 CFR Part 50, to manage the leaktightness of the cable

feed-through assembly. The staff concludes that the applicant has properly applied the scoping

criteria of 10 CFR 54.4(a) to the ANO-2 containment penetrations. Therefore, the staff

considers its concern described in RAI 2.4-8 resolved.

2.4.2.3 Conclusion

The staff reviewed the LRA and related structural/component information, including the

accompanying scoping boundary drawings (if applicable), to determine if the applicant failed to

identify any SSCs that should be within the scope of license renewal. The staff did not find any

omissions. In addition, the staff performed an independent assessment to determine whether

the applicant failed to identify any components that should be subject to an AMR. The staff did

not find any omissions. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the containment and containment internals that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the'components of the containment and containment internals that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.3 Auxiliary Buildings, Turbine Building, and Yard Structures

In Section 2.4.2 of the LRA, the applicant described the auxiliary buildings, turbine building, and

yard structures.

2.4.3.1 Summary of Technical Information in the Application

The ANO-2 auxiliary building is a seismic Category 1 structure. The auxiliary building houses

various systems that support operation of ANO-2. It is a conventionally designed, reinforced

concrete structure founded on bedrock east of the ANO-2 containment. The auxiliary building

consists of a reinforced concrete foundation, reinforced concrete floor slabs, and a tiered

reinforced concrete roof with an elastomeric coating or sheet metal roof decking with builtup

roofing on rigid insulation. The building is partly above grade (grade is at Elevation 354'-0") and

partly below grade. Exterior concrete construction joints contain waterstops at joints below the

plant's design flood level.

The auxiliary building contains reinforced masonry block walls that subdivide building areas into

separate rooms. They may be seismic Category 1 or 2. Block walls may be fire barriers

required for compliance with 10 CFR 50.48. Masonry block walls considered to have a safety

function must meet the requirements of NRC IE Bulletin 80-11.

The spent fuel pool's concrete walls are resistant to missiles and are lined with a stainless steel

liner plate. The liner plate protects the concrete walls from borated water leakage.

The post-accident sampling system (PASS) building contains seismic Category 2 equipment,

but it is designed to seismic Category 1 criteria to avoid potential interaction with safety

systems. It is also flood tight.

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The turbine building is within the scope of license renewal since it contains fire protection

commodities (e.g., fire doors and walls) and electrical cables required for regulated events

listed in 10 CFR 54.4(a)(3).

Generally, yard structures within the scope of license renewal are seismic Category 1, and they

support and protect seismic Category 1 and 2 equipment. The foundation for the safety-related

condensate storage tank, T41 B, is a seismic Category 1 structural component on the west side

of the ANO-1 containment. The tank is supported on a reinforced concrete mat foundation.

Two valve pits are partially underneath and on opposite (north and south) sides of the mat

foundation. The south valve pit is for ANO-1 and the north valve pit serves ANO-2. A

reinforced concrete wall surrounds the lower portion of the tank to protect against loss from an

external missile. The missile wall is integral to the safety-related condensate storage tank

foundation mat.

A reinforced concrete pipe trench runs from T41 B to the ANO-2 auxiliary building wall. It is

surrounded by backfill material and situated on natural soil or backfill material. Figure 3.8-34 of

the SAR shows a section through the trench.

The emergency diesel fuel oil storage tank vault is a rigid reinforced concrete box structure on

the northwest side of containment. It contains four diesel fuel storage tanks (T57A, T57B,

2T57A, and 2T57B) in separate rooms to protect against fire and flooding. The walls are

designed to withstand hydrostatic loading over their full height. The structure has a mat

foundation founded on rock. Entry to the vault is through a watertight door. Additionally, a

3-hour fireproof door separates each storage tank room from the others.

The alternate ac generator building is a seismic Category 2 structure north of and adjacent to

the north side berm of the bulk fuel oil storage tank (T-25). The building is of steel-framed,

precast concrete construction with a steel-framed roof and reinforced concrete slab, founded on

grade beams supported by drilled in piers (caissons). This building houses the engine.

generator set, fuel oil transfer pump, fuel oil day tank, air start system, engine generator control

cabinets, HVAC, and fire protection systems.

Seismic Category 1 electrical manholes 2MHO1, 2MH02, and 2MH03 are at various locations on

the plant site. They are relatively small, reinforced concrete structures founded either on

natural soil or backfill materials. Backfill material surrounds these partially underground

structures. An access opening in the top slab, at grade level, is provided with a missileresistant steel or reinforced concrete cover.,

The RWT, 2T-3, is on a concrete slab that is part of the auxiliary building. The slab is the roof

of the 2T12 tank vault (Room 2020). A small ring wall, filled with oiled sand, placed on the top

of the concrete slab separates the tank bottom from the concrete.

The applicant evaluated the following SCs for the auxiliary building, turbine building, and yard

structures: -

* alternate ac generator building -

* auxiliary building sump (except valves and piping)

* building foundations.

* concrete beams

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* crane rails and crane support structures

* doors (e.g., flood doors and fire doors)

* external penetrations and louvers

* embedded items (including conduit, unistrut, and anchors)

* exterior and interior concrete walls

* floor and roof slabs

* fuel transfer tube support

* HELB barriers such as walls, floors, and doors

* main transformer foundations

* manway hatches (concrete and steel)

* masonry block walls

* miscellaneous structural steel floor framing, columns, bracing, platforms, and catwalks

* new fuel racks

* outside electrical concrete manholes and underground ducts

* outside pipe trenches

* pipe supports, cable trays, conduits, and other equipment supports

* safety-related condensate storage tank (T-41 B) foundation and pipe trenches

* RWT (2T-3) foundation

* superstructure framing (over spent fuel pool)

* sump structures excluding piping, equipment, and l&C associated with the sump

* spent fuel pool concrete and liner plate

* spent fuel pool bulkhead gates

* spent fuel crane (L3)

* steel beams

* stairways, platforms, ladders, handrails, gratings, and catwalks

* steel floor framing, columns, and bracing

* tank foundations

* unit auxiliary transformer foundations

* Startup Transformer #3 foundations

* transformer yard concrete firewalls/missile barriers

* transformer bus structural steel supports and foundations

* switchyard startup #3 voltage regulator foundation

* switchyard bus structural steel supports and foundation

* switchyard circuit breaker 1 262F03 foundation

The auxiliary building, turbine building, and yard structures have no unique supports. Instead,

the bulk commodity review will address the supports.

In Table 2.4-2 of the LRA, the applicant identified the auxiliary building, turbine building, and

yard structures component types that are within the scope of license renewal and subject to an

AMR, including alternate ac generator building (framing and structural shapes), battery racks,

control room extension substructure, EDG stack vent exterior louvers, exhaust stack supports

(EDGs and EFW turbine), fuel handling bridge assembly (2H3) crane rails and girders, HELB

doors, new fuel racks, spent fuel overhead cranes (L3 and 2L35), spent fuel pool bulkhead

gates, spent fuel pool liner (auxiliary building), spent fuel pool superstructure framing (includes

associated structural shapes, bars, and plates), switchyard bus structural steel supports, tank

2T1 2 vault beams, watertight and flood doors, alternate ac generator foundation slab, auxiliary

building columns and beams, auxiliary building exterior walls (above grade), auxiliary building

exterior walls (below grade), auxiliary building floor slabs, auxiliary building interior load-bearing

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walls, auxiliary building foundation mat, auxiliary building sump, 'seismic Category 1 electrical

structures (manholes, walls, slabs, and ductwork), transformer bus structural supports, seismic

Category 1 electrical manhole covers; seismic Category 1 masonry block walls, emergency

diesel fuel oil storage tank vault (walls, floor slab, and columns), fuel oil storage tank T-25

foundation, PASS building substructure, roof slabs, RWT 2T-3 foundation slab, sodium

hydroxide tank 2T1 0 foundation, spent fuel pool bottom slab and walls, Startup Transformer #3

foundation,-Startup Transformer #3 concrete firewalls and missile shield, switchyard bus

structural foundation, and switchyard circuit breaker foundation.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and the referenced ANO-2 UFSAR Sections 3.8.4.1.1,

3.8.4.1.5, 3.8.4.1.6, 3.8.4.1.7, 6.2.2.2.11.B, and 8.3.3.2.1. The staff conducted its review in

accordance with the guidance described in Section 2.4 of the SRP-LR.

In the performance of the review, the staff evaluated the UFSAR to determine if the applicant

failed to identify any structural or component functions of the auxiliary building, turbine building,

and yard structures as an intended function, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then Verified that the

passive, long-lived components are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.2 identified an area in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 14, 2004. the staff issued RAI 2.4-4; given below, to the

applicant concerning the specific issues to determine whether the applicant has properly

applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1):

Please clarify the complete scope of liquid storage tanks and tank

foundations/supports included in the ANO-2 LR scope. UFSAR Tables 3.6-25,

3.6-26, and 3.6-27 list liquid storage tanks located outside buildings, inside

containment, and in the'auxiliary building, respectively. It is not clear to the staff

(1) whether all the listed Seismic Category I tanks and their foundations/supports

are included in the LR scope; and (2) whether any of the Seismic Category II

tanks and/or their foundations/supports need to be included in the LR scope due

to seismic 11/I considerations. Furthermore, the foundations for tanks T-41 B and

T-25 are identified as structures within the scope of LR in LRA Table 2.2-3, but

these tanks are not listed in the UFSAR tables.

Therefore, the applicant is requested to (1) provide a list of all liquid storage

tanks and tank foundations/supports included in the LR scope; (2) define the

associated intended function(s); (3) provide the'technical basis for exclusion of

any tanks (and their foundations/supports) that are listed in the UFSAR tables;

(4) identify the specific table'and row in 'LRA Section 2.3 or 2.4 that includes

each in-scope liquid storage tank and tank foundation/support; and (5) identify

the location in LRA Section 3 that contains the AMR for each tank and tank

foundation/support.

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The applicant's response to RAI 2.4-4, dated May 19, 2004, is given below:

The seismic category I tanks (and their foundations/supports) listed in SAR

Table 3.6-25 through Table 3.6-27 are in scope and subject to aging

management review. Some Seismic Category II tanks and their foundations are

included in the license renewal scope due to seismic li/I considerations and due

to other 1 OCFR54.4(a)(2) considerations. Tanks T-41 B and T-25 are addressed

in Section 1.2.2.10 of the ANO-2 SAR. Section 9.5.4 of the ANO-2 SAR

provides additional information on the T-25 tank. These tanks are not listed in

the referenced SAR tables since they are designated as ANO-1 components,

which are shared with ANO-2. The following addresses the five requested items:

(1) Even though not all tanks are in the scope of license renewal, all

tank foundations in containment and the auxiliary building are in

the scope of license renewal. The outside tanks which are in the

scope of license renewal also include the foundation as being in

scope. Tanks in the auxiliary building that are not subject to aging

management review are those that are nonsafety-related and

have no potential for failure to prevent accomplishment of a safety

function.

(2) As listed in Tables 2.4-2 and 2.4-4, intended functions for tank

foundations/supports are support of (a)(1), (a)(2) or (a)(3)

equipment. The intended function for tanks is "pressure

boundary" as reflected in the various tables listed in Section 2.3 of

the LRA.

(3) Tanks in the auxiliary building (Table 3.6-27) that are excluded are

those that are nonsafety-related and have no potential for failure

to prevent accomplishment of a safety function. Most of the

Seismic Category II tanks listed in Table 3.6-27 are in the turbine

auxiliary building in areas containing nonsafety-related equipment

or are abandoned in place. The waste tanks and the waste

condensate tanks are in service and in the auxiliary building and

are subject to aging management review. Tank foundations or

supports in the auxiliary building and containment are included

under the line items "anchors" and "equipment pads" in Table

2.4-4. Seismic category 11 tanks in SAR Table 3.6-25 are

excluded on the technical basis that they do not perform a license

renewal intended function. They are neither safety-related nor

required for compliance with regulations governing the regulated

events. Their failure cannot prevent the satisfactory

accomplishment of a required safety function.

(4) As listed under line item "Tank" Table 2.3.2-1, 2.3.2-2, 2.3.3-3,

2.3.3-4, 2.3.3-5, 2.3.3-6, 2.3.3-7, 2.3.3-8, 2.3.3-10, and 2.3.3-11.

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I
As listed in Table 2.4 2 under line item: RWT 2T3 foundation, fuel

oil storage tank T-25 foundation, sodium hydroxide tank 2T10

foundation, T41 tank foundation.

Inside tank foundations and supports are included in the LRA as

reflected in Table 2.4-4 under uanchors" and 'equipment pads."

(5) As shown under the same line item in Tables, 3.2.2-1, 3.2.2-2,

3.3.2-3, 3.3.2-4, 3.3.2-6, 3.3.2-7, 3.3.2-10, 3.3.2-11, 3.4.2-3,

3.5.2-2, and 3.5.2-4.

Based on its review, the staff finds the applicant's response to RAI 2.4-4 acceptable, because

the information submitted is sufficient to address the staff's concerns. The applicant has

adequately clarified (1) the complete scope of liquid storage tanks and tank

foundations/supports included in the ANO-2 license renewal scope, (2) intended functions, (3)

the technical basis for exclusion of any tanks (and their foundations/supports) that are listed in

the UFSAR tables, (4) the scoping and screening references in LRA Sections 2.3 and 2.4, and

(5) the AMR references in LRA Sections 3.2, 3.3, 3.4, and 3.5. The staff concludes that the

applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria

of 10 CFR 54.21 (a)(1) to the ANO-2 liquid storage tanks and tank foundations/supports.

Therefore, the staff considers its concern described in RAI 2.4-4 resolved.

The staff's review of LRA Section 2.4.2 identified a second area in which it needed additional

information to complete its evaluation of the applicant's scoping results. Therefore, by.letter

dated April 14, 2004, the staff issued RAI 2.4-6 (part a), given below, to the applicant

concerning the specific issues to determine whether the applicant has properly applied the

scoping criteria of 10 CFR 54.4(a):

UFSAR Tables 3.7-12, 3.7-13, and 3.7-14 list concrete block walls that appear to

serve intended functions, as defined by 10 CFR 54.4(a). The applicant is

requested to (1) verify that all of the listed walls are within the LR scope; (2) if

not, then provide the technical basis for any. exclusions; (3) identify any

additional block walls, not listed in the tables, that are included in the LR scope;

and (4) explain the statement "No Access For xx-B-xx" in UFSAR Table 3.7-14

under "Remarks".

The applicant's response to RAI 2.4-6 (part a), dated May 19, 2004, is given below:

(1) The walls listed in SAR Tables 3.7-12, 3.7-13 and 3.7-14 are within the

scope of license renewal and subject to aging management review.

(2) There are no exclusions from the above list of block walls.

(3) All seismic category I block walls located within the auxiliary, building are

included in scope. Also included are 50.48 required block walls located in

the turbine building.

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(4) "No Access For xx-B-xW' indicates that one side of the wall is in a high

radiation area making it inaccessible for routine inspection (e.g., 24-B-29

is the front face of the wall and 24-B-30 is the opposite face).

Based on its review, the staff finds the applicant's response to RAI 2.4- 6 (part a) acceptable,

because the information submitted is sufficient to address the staff's concerns. The applicant

has (1) verified that all walls listed in UFSAR Tables 3.7-12, 3.7-13, and 3.7-14 are within the

scope of license renewal and subject to an AMR, (2) identified that the block walls located in the

turbine building and required by 10 CFR 50.48 are also included within the scope of license

renewal and subject to an AMR, and (3) adequately explained the statement "No Access for

xx-B-xx" in UFSAR Table 3.7-14, under "Remarks." The staff concludes that the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) to the ANO-2 concrete block walls.

Therefore, the staff considers its concern described in RAI 2.4- 6 (part a) resolved.

The staff's review of LRA Section 2.4.2 identified a third area in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 14, 2004, the staff issued RAI 2.4-7, given below, to the

applicant concerning the specific issues to determine whether the applicant has properly

applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1):

LRA Section 2.4.2 covers the very broad structural category "Auxiliary Building,

Turbine Building and Yard Structures". LRA Section 2.4.2 describes the

in-scope structures and structural components under both "Description" and

'Evaluation Boundaries"; and then refers to LRA Table 2.4-2 for "Components

Subject-to AMR". The staff cannot clearly define the specific scope of structures

and structural components addressed in LRA Section 2.4.2 and cannot correlate

which in-scope structures and structural components are subject to AMR.

Consequently, the applicant is requested to provide the following additional

information:

(a) A complete and concise list of all the structures and structural

components that are included in LRA Section 2.4.2.

(b) For each listed structure and structural component, identify the intended

function(s).

(c) For each listed structure and structural component, identify whether it is

subject to AMR.

(d) If only part or none of the structure or structural component is subject to

AMR, then provide the technical basis for the determination.

NOTE: The staff has requested additional information for load handling

systems, tank foundations/supports, and concrete block walls in other RAls. For

these items, the applicant may reference the responses to the other RAls in its

response to (b), (c)), and (d) above.

The applicant's response to RAI 2.4-7, dated May 19, 2004, is given below:

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(a) The applicant provided a listing of all structures and components that are

within the scope of the auxiliary building, turbine building, and yard

structures.,

(b) The intended functions for the structures and structural components are

provided in Tables 2.4-2 and 2.4-4 of the application.

(c) The components subject to an aging management review are

summarized in the above table and specifically addressed in Tables

3.5.2-2 and 3.5.2-4.

(d) The turbine building has been included in the scope of license renewal

because part of the building contains commodities that are subject to

aging management review. These commodities include 10 CFR 50.48

fire walls/floors, missile barriers, and component supports (associated

with the station blackout function) which are located in the turbine,-

building at various locations: The remaining portions do not perform an

intended function.

Based on its review, the staff concluded that the table presented in part (a) of the applicant's

response, which summarizes the structures and structural components included in LRA Section

2.4.2 and identifies the applicable LRA Section 2.4 and 3.5 table entries, provides sufficient

information to address parts (a), (b), and (c)) of the RAI. The staff finds the applicant's

response to parts (a), (b), and (c)) of the RAI to be acceptable.

However, based on its review, the staff did not find the applicant's response to RAI 2.4- 7,

part (d), to be acceptable. It does not address the unit auxiliary transformer foundation and the

main transformer foundation. In addition, from the discussion of the turbine building in part (d)

of the response, the staff could not determine if the applicant included the entire turbine building

within the scope of license renewal, or if the building has been zoned to include only portions

that contain commodities that are subject to anAMR. In a meeting on July 20,2004, the staff

requested the applicant to submit the technical basis for concluding that the unit auxiliary

transformer foundation and the main transformer foundation are not subject to an AMR, and to

clarify its treatment of the turbine building.;

The applicant's supplemental response to RAI 2.4-7, part (d), dated July 22, 2004, is given

below:

As noted in the response to RAI 2.5-2 (correspondence dated June 21, 2004

(2CAN060404)), neither the main transformers nor the auxiliary transformer are

included in the station blackout recoveryjpath. Neither the main transformers nor

the auxiliary transformer perform a safety-related function, affect a safety-related

function, or are credited for a regulated event, so they are not subject to aging

management review. Thus, their foundations are not subject to aging

management review. The turbine building (as a whole) is in the scope of license

renewal because it contains commodities that are subject to aging management

review. , -

t2-109
Based on its review, the staff finds the applicant's supplemental response to RAI 2.4-7, part (d),

acceptable because it adequately describes the basis for excluding the unit auxiliary

transformer foundation and the main transformer foundation from the scope of license renewal.

In addition, it clarifies that the whole turbine building is included within the scope of license

renewal. The staff concludes that the applicant has properly applied the scoping criteria of

10 CFR 54.4(a). Therefore, the staff considers its concern described in RAI 2.4-7 resolved.

On March 1 to 5, 2004, the NRC staff performed a scoping and screening inspection at ANO-2.

During the inspection, the NRC staff noted that cabling necessary for coping with a station

blackout event was supported by the concrete floor slab in the switchyard control house. In

accordance with 10 CFR 54.4(a)(3), the applicant had appropriately included the cabling in the

scope of license renewal as a system relied on for meeting the NRC's station blackout rule

(10 CFR 50.63). However, the applicant did not include the structure on which it was mounted.

The staff stated that as the cabling could not perform it's station blackout coping function

without adequate support, its structural support system must also be in the scope of license

renewal. The applicant agreed to include the entire structure in the scope of license renewal.

Subsequent to the inspection, the applicant told the staff that despite this omission, the floor

slab was included in a program for managing the effects of aging.

The NRC staff inspection identified an item requiring action by the applicant. The item listed

above is identified in the ANO-2 Inspection Report, dated April 19, 2004 (ML0411006481). The

applicant indicated that the concrete floor slab was included in an aging management program.

The aging management review is discussed in Section 3.5.2.3.2. The final disposition of this

item was addressed by the Aging Management Review Inspection Report, dated January 9,

2005.

2.4.3.3 Conclusion

The staff reviewed the LRA and related structural/component information, including the

accompanying scoping boundary drawings (if applicable), to determine whether the applicant

failed to identify any SSCs that should be within the scope of license renewal. The staff found

one omission as indicated above. The staff concludes that the omission was a human error

made in implementing the scoping and screening process and not indicative of an inadequate

scoping and screening methodology. In addition, the staff performed an independent

assessment to determine whether the applicant failed to identify any components that should be

subject to an AMR. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the auxiliary building, turbine building, and yard

structures that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the

components of the auxiliary building, turbine building, and yard structures that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.4.4 Intake Structure and Emergency Cooling Pond

2.4.4.1 Summary of Technical Information in the Application

In Section 2.4.3 of the LRA, the applicant described the intake structure and emergency cooling

pond. The intake structure is in the southeast corner of the plant site. It is a reinforced

concrete seismic Category I structure considered an extension of the ANO-1 intake structure.

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There is no separation between the two structures, and both are founded on rock. It supports a

common gantry crane to service the equipment. The structure'can be divided into two major

sections. The first section is the portion of the building above grade elevation (Elevation

353'-3").

The remaining section is the pump bay area below grade and partially submerged in water.

The intake section of the building has two bays. The back section of the building is a box-type

structure that houses the major equipment'(e.g.4 service water pumps and associated

equipment). The abovegrade section consists of three predominant elevations-Elevation

354'-0n, Elevation 366'-0", and Elevation 378'-0u. Missile shield walls are'provided at the

exterior of the intake structure doorways. Roof plugs above service water pumps function as

missile shields and can be removed to provide maintenance access.

The ANO-1 intake structure is integrally connected to the ANO-2 intake structure with a shear

key and a row of reinforcing bars near the Elevation 354'-0N slabs. The ANO-1 structure

houses the common fire pumps and accessories in the seismic Category 1 portion of the

structure.

The intake canal associated with the intake structure provides a suction source for fire water

and service water pumps. The canal is approximately 1219 meters (4000 feet) long, with an

average depth of 4 meters (14 feet). The normal water elevation is Elevation 338'-0".

The emergency cooling pond is a seismic Category 1, 14-acre, kidney-shaped pond northwest

of the plant. Plant discharge (emergency cooling pond inlet) flows into a structure that is

surrounded by a 30-meter- (100-foot-) long weir. The emergency cooling pond is'excavated in

an impervious clay stratum, with the bottom'of the pond above bedrock. Riprap placed on the

north side of the pond protects the pond side slopes against wave action.

The applicant evaluated the following SSCs for the intake structure and emergency cooling

pond:

* structural steel elements, such as floor framing, columns, bracing, platforms, and

catwalks

* external penetrations and doors

* bar grates and fish baskets

* building foundations

* concrete beams

* concrete missile barriers

* crane rails and crane support structures

* discharge canal concrete flume - :

* embedded items (including unistruts and anchors)

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* exterior and interior concrete walls

* emergency cooling pond concrete intake

* emergency cooling pond and intake canal

* floor and roof slabs (including portions associated with ANO-1 fire water pump)

* hatches (including ANO-11)

* louvered doors (including ANO-11)

* pipe supports, cable trays, and other equipment supports

* service water screens/filters/strainers

* steel beams

* traveling screens

The intake structure and emergency cooling pond evaluation has no unique supports. Instead,

the supports are addressed with the bulk commodities.

In Table 2.4-3 of the LRA, the applicant identified the intake structure and emergency cooling

pond component types that are within the scope of license renewal and subject to an AMR,

including beams in service water and circulating water bays, floor hatches, louvered doors,

support for roof hatches, submerged pump shaft supports, building foundation, columns and

beams, emergency cooling pond concrete intake, exterior walls (above grade), exterior walls

(below grade), floor slabs, interior walls, roof slab, emergency cooling pond, and intake canal.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and the referenced ANO-2 UFSAR Sections 9.2.5,

3.8.4.1.2, and 3.8.4.1.4. The staff conducted its review in accordance with the guidance

described in Section 2.4 of the SRP-LR.

In the performance of the review, the staff evaluated the UFSAR to determine if the applicant

failed to identify any structural or component functions of the intake structure and emergency

cooling pond as an intended function, in accordance with the requirements of 10 CFR 54.4(a).

The staff did not identify any omissions. The staff then verified that the passive, long-lived

components are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of the LRA Section 2.4.3 identified an area in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 14, 2004, the staff issued RAI 2.4-5, given below, to the

applicant concerning the specific issue to determine whether the applicant has properly applied

the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1):

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Based on review of ANO-2 LRA Section 2.4.3, the referenced UFSAR Section

9.2.5, and the ANO-1 LRA, the staff requires additional information before it can

conclude that all the necessary elements of the "ultimate heat sink" for ANO-2

have been included in the LR scope.

(a) From LRA Section 2.4.3, it appears that only the water in the emergency

cooling pond and the intake canal are needed for safe shutdown of

ANO-2. However, for ANO-1, the discharge canal was also included as

part of the 'ultimate heat sink". The applicant is-requested to explain this

apparent discrepancy.

(b) UFSAR Section 9.2.5.2.1 and (to a lesser extent) ANO-2 LRA Section

2.4.3 describe various components of the ECP, such as the pipe inlet and

outlet structures, the 100 foot long weir, and the ECP spillway. It is not

evident to the staff which components described in UFSAR Section -

9.2.5.2.1 are essential to the Uultimate heat sink" function and are

included within the LR scope. The applicant is requested to (1) identify

all components essential to the 'ultimate heat sink" function and included

in the LR scope; (2) provide the technical basis for exclusion from the LR

scope of any components described in UFSAR Section 9.2.5.2.1; (3)

identify the specific row in LRA Table 2.4-3 that includes each in-scope

component; and (4) identify the location in LRA Section 3 that contains

the AMR for each component.

The applicant's response to RAI 2.4-5, dated May 19, 2004, is given below:

(a) The discharge canal is not credited as part of ANO-2's ultimate heat sink. -

As stated in ANO-2 SAR Section 9.2.1.2.3.7, "Under accident conditions

the SWS discharge is automatically changed to the ECP upon the

initiation of an SIAS or MSIS." The ANO-1 service water system

discharge is not automatically changed to the ECP under accident

conditions so the discharge canal is credited as part of the ultimate heat

sink for ANO-1. -

(b) (1) Structural ECP components essential to the "ultimate heat sink"

:function and included in the license renewal scope are the pond, the

pond inlet and pond outlet structures and the ECP spillway. Associated,,

piping to and from tie points to the service water system is in scope as

part of the service water system.-

(2) The 225-acre watershed area listed in SAR Section 9.2.5.2.1 is

excluded from the license renewal scope since no makeup to the pond is

credited after an accident begins.

(3) The specific rows in LRA Table 2.4-3 that address the inlet and outlet

structures and the pond are 'ECP concrete intake" and "emergency.

cooling pond". The row labeled upiping" in Table 2.3.3-8 addresses the

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piping to and from the ECP. The spillway and 100-foot long weir are

included in the line item 'emergency cooling pond."

(4) As listed under the same line items in Tables 3.5.2-3 and 3.3.2-8.

Based on its review, the staff finds the applicant's response to RAI 2.4-5 acceptable, because

the information submitted is sufficient to address the staff's concern. The response to part (a)

of the RAI adequately explains why the discharge canal does not serve an intended function for

ANO-2 and is not included within the scope of license renewal for ANO-2. The response to

part (b) of the RAI (1) clarifies which components are essential to the ultimate heat sink function

and included within the scope of license renewal, (2) provides an adequate technical basis for

exclusion of the 225-acre watershed area, (3) identifies the specific rows in LRA Tables 2.4-3

and 2.3.3-8 that include each in-scope component, and (4) identifies the location in LRA Tables

3.5.2-3 and 3.3.2-8 that contain the AMR for each component. The staff concludes that the

applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria

of 10 CFR 54.21 (a)(1) to the ANO-2 ultimate heat sink. Therefore, the staff considers its

concern described in RAI 2.4-5 resolved.

2.4.4.3 Conclusion

The staff reviewed the LRA and related structural/component information, including the

accompanying scoping boundary drawings (if applicable), to determine whether the applicant

failed to identify any SSCs that should be within the scope of license renewal. The staff did not

find any omissions. In addition, the staff performed an independent assessment to determine

whether the applicant failed to identify any components that should be subject to an AMR. The

staff did not find any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the intake structure and emergency

cooling pond that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the components of the intake structure and emergency cooling pond that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.5 Bulk Commodities

2.4.5.1 Summary of Technical Information in the Application

In Section 2.4.4 of the LRA, the applicant described bulk commodities. Structural commodities

are structural members that support or protect system components, mechanical piping,

electrical lines, and plant equipment. Structural commodities that are unique to a specific

structure are evaluated with that structure. Structural commodities which are common to

ANO-2 in-scope systems and structures (e.g., anchors, embedments, equipment supports,

instrument panels, racks, cable trays, and conduits) are evaluated as bulk commodities.

To support a system component within the scope of license renewal, the structure may transfer

dead, live, thermal, vibration, impact, seismic, or wind loads applied to or generated by the

affected system component. For a structure to perform a protective function for an in-scope

system component, the structure must have sufficient strength and resiliency to ensure that the

system component is protected from the effects of design-basis events, such as flood, fire, jet

impingement, and missiles.

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The SSCs reviewed as bulk commodities include the following:

* anchor bolts

* base plates and embedded unistrut

* battery racks

* cable tray and conduit supports

* cable trays

* component supports

* damming material (fire barrier)

* electrical instrument panels and enclosures

* fire barrier seals

* fire damper framing (in-wall)

* fire doors

* flood curbs

* floor plugs

* hatches

* HVAC duct supports

* -instrument line supports

* instrument racks and frames

* joint elastomers at seismic gaps

* lightning protection poles and attachments

* main steamline support structure

* manhole covers . -,

* miscellaneous embedment ; -- .

* miscellaneous doors, louvers, wire mesh; safety chains, and safety gates

* missile barriers

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* monorails, crane rails, and girders

* penetration seals

* pipe sleeves (mechanical/electrical, not penetrating the containment liner plate)

* piping supports (includes whip restraints)

* RCS component support threaded fasteners (for steam generators, RCPs, and

pressurizer)

* roofing

* stairs, ladders, handrails, catwalks, platforms, and grating

* support pedestals (pads)

* threaded fasteners

* trisodium phosphate baskets

* waterstops

In Table 2.4-4 of the LRA, the applicant identified the bulk commodities component types that

are within the scope of license renewal and subject to an AMR, including base plates, cable tray

and conduit supports, embedded unistrut, components supports (e.g., instrument racks and

frames), electrical instrument panels and enclosures, fire damper framing, fire doors, fire hose

reels, HVAC missile barriers, main steamline support structure, monorails, crane rails and

girders, pipe sleeves (not penetrating containment liner plate), piping supports, piping whip

restraints, stairs, ladders, platforms, grating (supports), anchor bolts, other threaded fasteners,

reactor cavity missile block tie-downs, equipment pads, fireproofing, flood curbs, hatches and

plugs, missile shields, support pedestals, equipment hatch seals, fire barrier seals, fire wrap,

joint elastomers at seismic gaps, penetration seals, and waterstops.

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4, which does not include any references to the UFSAR for

the bulk commodities. The staff conducted its review in accordance with the guidance

described in Section 2.4 of the SRP-LR.

In the performance of the review, the staff determined if the applicant failed to identify any

structural or component functions of the bulk commodities as an intended function, in

accordance with the requirements of 10 CFR 54.4(a). The staff also verified that the passive,

long-lived components are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of the LRA Section 2.4.4 identified several areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 14, 2004, the staff issued RAI 2.4-2, given below, to the

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I
applicant concerning the specific issues to determine whether the applicant has properly

applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1):

Based on its review of LRA Sections 2.1, 2.2, 2.3, 2.4, and 2.5, the staff

'identified a number of scoping and'screening issues that require clarification and

additional information. It is not clear to the staff how the applicant has

addressed the'following commodities in its'scoping and screening evaluation:

cable trays, conduit, instrument lines, TubeTrac (if applicable), thermal insulation

on piping and/or structures that performs an intended function. The applicant is

requested to (1) specifically describe the treatment of each of these commodities

in its scoping and screening evaluation; (2) identify the specific table and row in

LRA Section 2.3, 2.4, or 2.5 that includes each commodity; and (3) identify the

location in LRA Section 3 that contains'the AMR for each commodity.

The applicant's response to RAI 2.4-2, dated May 19, 2004, is given below:

Cable trays: - ;:

(1) Cable trays were treated as in scope and subject to aging management

review.

(2) Table 2.4-4, under the entry 'Cable tray and conduit supports, embedded

unistrut."

(3) As shown in Table 3.5.2-4 under the same component entry.

Conduit: - ;

(1) Conduit was treated as in scope and subject to aging management

review. :

(2) Table 2.4-4,' under the entry uCable tray and conduit supports, embedded

unistrut." - -

(3) As shown in Table 3.5.2-4 under the same component entry.

Instrument lines:

(1) Instrument lines were treated as: in scope and subject to aging

management review. 'This component is referred to as tubing in the LRA.

(2) As shown in the following tables.

2.3.1-3 2'.3.2-1: 2.3.2-2 2.3.2-4 2.3.2-5

- .- : - 2.3.3-2

2.3.3-3 - 2.3.3-4' 2.3.3-5 2.3.3-6 2.3.3-7,

2.3.3-8

2.3.3-9 2.3.3-10 :2.3.3-11 2.3.4-1 2.3:4-2

2.3.4-3

2.4-4

, . , , , . . . ..

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(3) Instrument line/tubing aging management review is addressed in the

following table:

3.1.2-3 3.2.2-1 3.2.2-2 3.2.2-4 3.2.2-5

3.3.2-2

3.3.2-3 3.3.2-4 3.3.2-5 3.3.2-6 3.3.2-7

3.3.2-8

3.3.2-9 3.3.2-10 3.3.2-11 3.4.2-1 3.4.2-2

3.4.2-3

3.5.2-4

TubeTrac:

(1) Tubing support systems, considered component supports, are in scope

and subject to aging management review.

(2) As listed in Table 2.4-4, under the entry "component supports."

(3) As shown in Table 3.5.2 4 under the same component entry.

Thermal insulation on piping and/or structures that performs an intended

function:

In some internal plant locations at ANO-2, insulation on piping has the intended

function to limit heat loss in order to reduce area heat loads during accident

conditions. This insulation is indoors and hence is protected from the weather.

A review of ANO-2 operating experience verified that the plant has not

experienced aging related degradation of piping insulation in indoor

environments. Therefore, based on operating experience, there are no aging

effects requiring management for indoor insulation at ANO-2. This is consistent

with NUREG 1705, which states: "The staff concludes that, even if the chemical

volume control system relied on the insulation to perform any accident mitigation

functions, there are no plausible aging effects for the insulation that would

warrant an aging management program."

Based on its review, the staff finds the applicant's response to RAI 2.4-2 acceptable for cable

trays, conduit, instrument lines, and TubeTrac, because the information submitted is sufficient

to address the staff's concerns. The applicant identified cable trays, conduit, instrument lines,

and TubeTrac as within the scope of license renewal and subject to an AMR. The applicant

identified the relevant applicable tables and row entries for the scoping and screening review

and for the AMR for each of these commodities. The staff concludes that the applicant has

properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1) to ANO-2 cable trays, conduit, instrument lines, and TubeTrac. Therefore,

the staff considers its concern described in RAI 2.4-2 resolved for cable trays, conduit,

instrument lines, and TubeTrac.

Based on its review, the staff did not find the applicant's response to RAI 2.4-2 acceptable for

thermal insulation, because the applicant's scoping and screening evaluation for thermal

insulation appears to be flawed. In its RAI response, the applicant indicated that some thermal

insulation has an intended function. However, the applicant apparently excluded this insulation

from the scope of license renewal on the basis that there are no aging effects requiring

management.

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The staff noted that the scoping process for thermal insulation serves to identify all thermal

insulation at ANO-2 that provides an intended function, in accordance with

10 CFR 54.4(a)(1-3). All thermal insulation that serves an intended function is within the scope

of license renewal.

In a rmeeting on July 20, 2004, the staff requested the applicant to identify any thermal

insulation at ANO-2 that serves an intended function, in'accordance with 10 CFR 54.4(a)(1-3),

describe plant-specific operating experience related to degradation of thermal insulation in

general and thermal insulation that serves an intended function, and describe the scoping and

screening evaluation for thermal insulation that serves an intended function, including the

technical basis for either inclusion within or exclusion from the scope of license renewal. The

staff indicated that the requested clarification should focus on insulation on hot containment

piping penetrations.

The applicant's supplemental response to RAI 2.4-2 for thermal insulation, dated August 18,

2004, is given below:

The insulation on hot containment piping penetrations is not required to ensure

the functions of 10 CFR 54.4(a)(1) are accomplished or to demonstrate

compliance with Commission regulations identified in 10 CFR 54.4(a)(3). The

insulation does not meet 10 CFR 54.4(a)(2) as its failure will not prevent

satisfactory accomplishment of any of the functions identified in

10 CFR 54.4(a)(1). Insulation on hot piping at containment penetrations does

support normal ventilation systems in maintaining the environment for

surrounding structural elements. However, maintaining the environment during

normal operation is not an intended function identified in 10 CFR 54.4(a)(1). The

fact that normal ventilation systems are not in the scope of license renewal

supports this conclusion. In summary, thermal insulation on hot piping at

containment penetration does not meet the scoping criteria of 10 CFR 54.4. This

is consistent with the previously approved staff position documented in the safety

evaluation report (SER) related to the license renewal of North Anna and Surry

power stations, NUREG-1766, Section 2.1.3.1.

Notwithstanding the above, Entergy performed an aging management review of

the insulation on hot containment piping penetrations for ANO-2 even though it is

not considered in the scope of license renewal. The aging management review

did not identify any aging effects requiring management. ANO-2 hot piping

penetration insulation is protected by its installation indoors in the annulus

between the penetration piping and the''penetration sleeve. The review of plantspecific operating experience for license renewal identified no age-related

degradation of thermal insulation indoors, including insulation on hot piping at

containment penetrations.

Degradation of concrete due to exposure to elevated temperatures is a long-term

process. Maintaining concrete temperatures below the degradation threshold

values during long-term, normal operation is essential to ensure that there is no

degradation of concrete properties. If thermal insulation on hot piping that

penetrates containment is relied on (solely or in conjunction with ventilation

systems) to meet the concrete temperature criteria, then the staff concludes that

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it serves an intended function for license renewal, in accordance with

10 CFR 54.4(a)(2), and needs to be included in the scope of license renewal.

In a letter dated September 15, 2004, the applicant stated that thermal insulation around hot

piping penetrations is included in the scope of license renewal for ANO-2. The applicant

performed an aging management review of the insulation. Based on the consideration of the

materia and environment, its protected location, and operating experience, there are no aging

effects requiring management for the insulation around hot piping penetrations. The staff

considers its concern described in RAI 2.4-2 resolved.

2.4.5.3 Conclusion

The staff reviewed the LRA and related structuralcomponent information, including the

accompanying scoping boundary drawings (if applicable), to determine whether the applicant

failed to identify any SSCs that should be within the scope of license renewal. In addition, the

staff performed an independent assessment to determine whether the applicant failed to

identify any components that should be subject to an AMR. On the basis of its review, the staff

concludes that the applicant has adequately identified the components of the bulk commodities

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the

components of the bulk commodities that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.5 Scoping and Screening Results-Electrical and Instrumentation and Controls

Systems

This section addresses the scoping and sc'reening results of electrical and I&C systems at

ANO-2 for license renewal. 'According to 10 CFR 54.21 (a)(1), an applicant must identify and list

SCs'subject to an AMR, which are passive, long-lived SCs that are within the scope of license

renewal. To determine whether that the applicant has properly implemented its methodology,

the staff focuses its review on the implementation results. Such focus allows the staff to

confirm that the applicant did not omit any electrical system components that are subject to an

AMR. If the review identifies no omission, the staff has a basis to find that the applicant has

identified the electrical system components that are subject to an AMR.

2.5.1 Summary of Technical Information In the Application

In LRA Table 2.5.1, the applicant listed electrical and instrumentation and control system

components that are within the scope of license renewal. The following'structure and

component/commodity groups'were identified by the applicant as within'the scope of license

renewal:

* Electrical cables and connections not 'subject to 10 CFR 50.49 EQ requirements

* Inaccessible medium-voltage ($.16kV to 34.5kV) cables not subject to 10 CFR 50.49 EQ

requirements

* Electrical connectors not subject to 10 CFR 50.49 EQ requirements that are'exposed to

borated water leakage,

* Switchyard bus (switchyard bus for SB0) bus bars, connections

* High voltage insulators

2.5.2 Staff Evaluation

The staff performed its evaluation of the information provided in the LRA in the same manner

for all electrical and I&C systems. Through its review, the staff sought to determine if the

applicant identified as within the scope of license renewal those'SSCs for a specific electrical or

I&C system that appear to meet the scoping criteria, in accordance with 10 CFR 54.4.

Similarly, the staff evaluated the applicant's screening results to determine whether all longlived, passive components are subject to an AMR, in 'accordance withi 0 CFR 54.21 (a)(1).

To perform its evaluation, the staff reviewed the applicable LRA section and associated

component drawings, focusing its review on components that the applicant did not identify as

within the scope of renewal. The staff reviewed relevant licensing basis documents, including

the UFSAR, for each electrical and l&C component to determine if the applicant omitted

components with intended functions delineated under 10 CFR 54.4(a) from the scope of license

renewal. The staff also reviewed the licensirigbasis documents to determine if all intended

functions delineated un'der 10 CFR 54.4(a)'are specified in the LRA. If it identified omissions,

the staff requested additional information tofresolve the discrepancy.

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Once the staff completed its review of the scoping results, it evaluated the applicant's screening

results. For those SCs with intended functions, the staff sought to determine if the functions

are performed with moving parts or a change in configuration or properties (i.e., passive), or if

they are subject to replacement based on a qualified life or specified time period (i.e., longlived), as described in 1 0 CFR 54.21 (a)(1). For those that do not meet either of these criteria,

the staff sought to confirm that these electrical and l&C components are subject to an AMR as

required by 1 0 CFR 54.21 (a)(1). If it identified discrepancies, the staff requested additional

information to resolve them.

The staff reviewed LRA Section 2.5 to determine if the applicant identified the electrical and l&C

systems and components within the scope of license renewal and subject to an AMR in

accordance with 1 0 CFR 54.4 and 10 CFR 54.21 (a)(1).

In performing the review, the staff selected system functions described in the FSAR and set

forth in 10 CFR 54.4 to determine whether the applicant did not omit components having

intended functions from the scope of the Rule. The staff also reviewed drawings and focused

on components that the applicant did not identify as subject to an AMR to determine if it omitted

any components.

As part of its review, the staff requested additional information in a letter dated May 25, 2004.

In RAI 2.5-1, the staff requested that the applicant explain why uninsulated ground conductors

are not subject to AMR. The applicant responded to the RAI in a letter to the staff dated June

21, 2004. In its response, the applicant stated that uninsulated ground conductors (e.g.,

grounding rods, buried ground cables, and cathodic protection) are not subject to AMR because

this commodity group does not perform a license renewal intended function. Furthermore,

noninsulated ground conductors do not meet any of the scoping criteria specified in

10 CFR 54.4. These components are not safety related per 10 CFR 54.4(a)(1) and are not

credited for mitigation of regulated events listed in 10 CFR 54.4(a)(3).

The applicant stated that industry and plant-specific operating experience for uninsulated

ground conductors does not indicate credible failure modes that would adversely impact an

intended function; therefore, equipment failures caused by uninsulated ground conductors are

considered hypothetical. As discussed in SRP-LR Section 2.1.3.1.2 and SOC Section IlI.c(iii)

(Volume 60 of the Federal Register, page 22467 (60 FR 22467)), hypothetical failures are not

required to be considered for license renewal if they are not included in the CLB. The applicant

also stated that the failure of an uninsulated ground conductor will not prevent satisfactory

accomplishment of any of the functions identified in 10 CFR 54.4(a)(1).

Based on this response, the staff concludes that uninsulated ground conductors do not perform

or support any safety-related functions or any of the regulated events identified in

10 CFR 54.4(a). Therefore, the passive electrical commodity of uninsulated ground

conductors is not within the scope of license renewal.

Table 2.5-1 of the LRA lists the commodity group "switchyard bus (switchyard bus for SBO),

bus bars, connections)." The staff requested the applicant to clarify whether this commodity

group includes the phase bus (e.g., isolated-phase bus and segregated and nonsegregated

phase bus). In its response to the staff RAI, the applicant stated that the commodity group

"switchyard bus (switchyard bus for SBO), bus bars, and connections" includes the phase bus

(e.g., isolated-phase bus and segregated and nonsegregated phase bus). This commodity

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group is subject to AMR since ANO-2 uses a nonsegregated phase bus to connect the offsite

ac power source (via the startup transformer) to the 4.16-kilovoit (kV) switchgear. Table 3.6.2-1

of the LRA includes the phase bus; however,-'the applicant did not identify any aging effects

requiring management for the phase bust' Plant-specific operating experience confirms that the

phase bus has satisfactorily performed its intended function since initial plant operation without

aging effects requiring management. Based on this information, the staff concludes that the

applicant did not omit the phase bus at ANO-2.

Table 2.5-1 of the LRA lists the commodity group "electrical cables and connections not subject

to 10 CFR 50.49 EQ requirements;' The staff requested the applicant to clarify whether this

commodity group'includes the electrical portions of electrical and I&C penetration assemblies

(e.g., electrical penetration assembly cables and connections). In its response to the staff RAI,

the applicant stated that the commodity group electrical cables and connections not'subject to

10 CFR 50.49 EQ requirements" includes the electrical portions of electrical and l&C

penetration assemblies (e.g., electrical penetration assembly cables and connections), and that

the applicant performed an AMR. The item on electrical cables and connections not subject to

10 CFR 50.49 EQ requirements in Table 3.6.2-1 identifies the aging effects and AMP for nonEQ electrical and l&C penetration cables and connections. Based on this information, the staff

concludes that the applicant did not omit the electrical penetration assembly cables and

connections at ANO-2.

Interim Staff Guidance (ISG)-2, UNRC Staff Position on License Renewal Rule (10 CFR 54.4)

As It Relates to the Station Blackout Rule (10 CFR 50.63)," states the following:

The offsite power systems consist of a transmission system (grid) component

that provides a source of power and a plant system component that connects the

power source to a plant's onsite electrical distribution systems which power

safety equipment. For the purpose of the license renewal rule, the staff has

determined that the plant system portion of the offsite power system that is used

to connect the plant to the offsite power source should be included within the

scope of the rule.

The staff requested the applicant to provide a detailed description of the ANO-2 recovery path

and discuss how the recovery path is included within the scope of license renewal to comply

with ISG-2. ,

In response to the staff's request, the'applicant, in a letter dated Jurine21, 2004, responded that

per ISG-2, the ANO-2 LRA scope for SBO includes the switchyard circuit breakers feeding

Startup Transformer #3, Startup Transformer #3, the circuit breaker-to-transformer and

transformer-to-onsite electrical interconnections, and the associated control circuits and

structures. Additionally, the applicant stated that it also included the voltage regulator since it is

part of the interconnection between the switchyard circuit breaker and the startup transformer.

The applicant further explained that the boundary between the transmission system (grid)

offsite power source and the plant system components is the 22-kV/41 6-kV startup transformer

(Startup Transformer #3). The 22-kV switchyard circuit breaker (B0126) that feeds Startup

Transformer #3 at ANO-2 is the offsite power connection point to the transmission system that

is the boundary point described in ISG-2 (first switchyard breaker). Medium-voltage insulated

cable, installed in an underground duct bank, runs between the switchyard circuit breaker

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B01 26 and the Startup Transformer #3 voltage regulator. A switchyard bus connects breaker

B0126 and the voltage regulator to the medium-voltage insulated cables. Medium-voltage

insulated cable, installed in an underground duct bank, runs between the voltage regulator and

Startup Transformer #3. A switchyard bus connects the voltage regulator and Startup

Transformer #3 to the medium-voltage insulated cables. High-voltage insulators, which are

used with the switchyard bus, are included in the scope of license renewal for the SBO recovery

path. Startup Transformer #3 is connected to the 4.16-kV safety buses with a nonsegregated

phase bus.

Instrument and control cables for the switchyard circuit breaker B01 26, the voltage regulator,

and Startup Transformer #3 are also included in the scope of license renewal for this recovery

path. The item for the program covering electrical cables and connections not subject to

10 CFR 50.49 EQ requirements, listed in LRA Table 3.6.2-1, includes these cables.

As described above, the applicant only included a single path for SBO recovery in its LRA.

That SBO recovery path includes the connections from Startup Transformer #3 to switchyard

circuit breaker B0126. During a July 20, 2004, public meeting, the staff requested that the

applicant include an alternate offsite power source in the scope of license renewal.

In a letter dated August 18, 2004, the applicant provided an alternate offsite power source in

the scope of license renewal. In the letter, the applicant stated that the alternate offsite power

source for Startup Transformer #2 is a component from ANO-1 credited for meeting General

Design Criterion (GDC) 17, "Electric Power Systems." As stated in the ANO-2 FSAR Section

8.1.4, ANO-2 can supply electric power to the onsite electric distribution system from two

physically independent transmission network circuits, Startup Transformer #3, which is an

ANO-2 offsite power component, and Startup Transformer #2, which is an ANO-1 offsite power

component. The switchyard autotransformer bank supplies Startup Transformer #3 through

underground cables. The 161 -kV switchyard ring bus supplies Startup Transformer #2.

Two 161-kV circuit breakers separate the 161-kV switchyard from the autotransformer. The

failure of any one of the 161 -kV circuit breakers will trip the adjacent circuit breakers and

interrupt only one of the plant offsite power sources. The 500-kV lines and the autotransformer

will remain available during that event. Conversely, the failure of a 500-kV circuit breaker which

feeds the autotransformer will trip the two 161 -kV circuit breakers connected to the

autotransformer but will not interrupt the 161 -kV circuit to the plant.

Section 8.2.1.2.G of the FSAR describes the overhead 161 -kV transmission conductors from

161 -kV switchyard circuit breakers B1291 and B1250 to Startup Transformer #2. The highvoltage insulators associated with the transmission conductors are similar to the high-voltage

insulators for the switchyard bus, which the applicant addressed in Section 3.6 of its LRA.

The inclusion of 161-kV switchyard circuit breakers B1291 and B1250 (first switchyard

breakers), the associated overhead transmission conductors, and Startup Transformer #2 in the

scope of license renewal required modification of the applicant's response to RAI 2.5-1 (c)),

provided in its June 21, 2004, letter.

In the revised response, the applicant stated that, based on the inclusion of Startup

Transformer #2, transmission conductors, strain and suspension insulators, and insulated

cables are subject to an AMR. The LRA includes insulated cables. The transmission

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conductors component type includes the transmission conductors and the hardware used to

secure the conductors to insulators. Section 3.6 of this SER pr6vides details of the applicant's

AMR of transmission conductors. Based on this information, the staff concludes that the

applicant did not omit transmission conductors at ANO-2.

2.5.3 Conclusion

On the basis of this review, the staff concludes that the applicant has adequately identified the

electrical and l&C systems and components that are within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a), and the electrical and l&C systems

components that are subject to an AMR in accordance with the requirements of

10 CFR 54.21 (a)(1).

2.6 Conclusion

The staff has reviewed the information in Section , "Scoping and Screening Methodology for

Identifying Structures and Components Subject to Aging Management Review and

Implementation Results " of the LRA. On the basis of its review, the staff concludes that the

applicant has identified those structures and components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and subject to an AMR, as required by 10 CFR

54.21 (a)(1).

With regard to these matters, the NRC staff has concluded that there is reasonable assurance

that the activities authorized by the renewed license will continue to be conducted in

accordance with the current licensing basis, and that any changes made to the ANO-2 current

licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the ACT and the

Commission's regulations.

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3. AGING MANAGEMENT REVIEW RESULTS

This Section of the SER contains the staff's evaluation of the applicant's aging management

programs (AMPs) and aging management reviews' (AMRs). In Appendix B of the LRA, the

applicant described the 33 AMPs that it relies on to manage or monitor the aging of long-lived,:

passive components and structures. In Section 3 of the LRA, the applicant provided the results

of the AMRs for those 'structures and components that were identified in Section 2 of the LRA

as being 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 license renewal application (LRA), Entergy Operations, Inc. (Entergy, the

applicant) credited NUREG-1801, 'Generic Aging Lessons Learned (GALL) Report," dated July

2001. The GALL Report contains the staff's generic evaluation of the existing plant programs

and documents the technical basis for determining where existing programs are adequate

without modification and where existing programs should be augmented for the extended period

of 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 structures or

components for license renewal without'ctihnge. The GALL Report also contains

recommendations'on specific areas for which existing programs should be augmented for

license"renewal. An applicant may ref erencethe GALL Report in its LRAto demonstrate that

the programs at its facility correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide'the ~staff with a summary of staff-approved AMPs

to manage or monitor the aging of structures'and components that are subject to an AMR. 'If an

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

used to review an'applicant's LRA will be greatly reduced, thereby improving the efficiency and

effectiveness of the license renewal review process. The GALL Report also serves as a

reference for applicants and staff reviewers to quickly identify those AMPs and activities that the

staff has determined will adequately managdeor monitor aging during the period of extended

operation. '

The GALL Report identifies (1) systems, structures, and components (SSCs), (2) structure and

component (SC) materials, (3) the environments to which the SCs are exposed, (4) the aging

effects associated with the materials and environments, (5) the AMPs that are 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 using the'GALL Report would improve the efficiency of the license

renewal review, the staff conducted a deimnnstrition project to exercise the GALL process and

to determine the format and content of a safety evaluation based on this process. The results

of the demonstration project confirmed that the GALL process will improve the efficiency and

effectiveness of the' LRA revievw While mairtaining'the staff's focus on public'health and safety.

NUREG-1800, Standard Review Plan for the Review'of License Renewal Applications," dated

April 2001 (SRP-LR), was prepared based on both the GALL Report model and lessons learned

from the demonstration project.

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The staff performed its work in accordance with the requirements of Title 10 of the Code of

Federal Regulations, Part 54 (10 CFR 54), "Requirements for Renewal of Operating Licenses

for Nuclear Power Plants;" the guidance provided in NUREG-1 800, 'Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated July 2001;

the guidance provided in NUREG-1 801, uGeneric Aging Lessons Learned (GALL) Report,"

dated July 2001; and the 'Audit and Review Plan for Plant Aging Management Reviews and

Programs - Arkansas Nuclear One, Unit 2" dated July 29, 2004 (ML041550872).

The staff performed audits and technical reviews of the license renewal applicant's AMPs and

AMRs. These audits and reviews are to determine whether the effects of aging on structures

and components can be adequately managed so that their intended functions can be

maintained consistently with the plant's current licensing basis (CLB) for the period of extended

operation as required by 10 CFR 54, "Requirements for Renewal of Operating Licenses for

Nuclear Power Plants."

During its review of the Arkansas Nuclear One, Unit 2 (ANO-2) LRA, the staff performed on-site

audits and reviews during the weeks of December 1, 2003, and February 9, 2004, to determine

that AMP and AMR results that the applicant claimed were consistent with the GALL Report

were actually consistent as claimed. Details of the staff's evaluation of the audits and reviews

are documented in the "Audit and Review Report for Plant Aging Management Reviews -

Arkansas Nuclear One, Unit 2 ," (ANO-2 Audit and Review Report) dated August 19, 2004

(ML0422400840).

The on-site audits and reviews are designed to maximize the efficiencies of the staff's review of

the LRA. The need for formal correspondence between staff and the applicant was reduced,

and therefore, improved the efficiency of the review. Also the applicant could respond to

questions, and the staff could readily evaluate the responses made by the applicant.

Overall, as set out in the SER, the staff determined that the applicant's aging management

activities and programs can adequately manage the effects of aging on structures and

components, so that their intended functions can be maintained consistent with the current

licensing basis (CLB) for the period of extended operation.

3.0.1 Format of the Licence Renewal Application (LRA)

Entergy Operations, Inc. (Entergy, the applicant) submitted an application that followed the

standard LRA format, as agreed to between the NRC staff and the Nuclear Energy Institute

(NEI) (see letter dated April 7, 2003). This revised LRA format incorporates lessons learned

from the staff's reviews of the previous LRAs. These previous applications used a format

developed from information gained during an NRC staff and NEI demonstration project

conducted to evaluate the use of the GALL Report in the staff's review process.

The organization of Section 3 of the LRA parallels Chapter 3 of the SRP-LR. The AMR results

information in Section 3 of the LRA is presented in the following two table types.

Table 1: Table 3.x.1 - where '3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, and N1" indicates that this is the first table

type in Section 3 of the LRA.

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Table 2: Table 3.x.2-y - where H30 indicates the LRA section number, "x" indicates the

subsection number of the GALL Report, "2"' indicates that this is'the second table type in'

Section 3 of the LRA, and "y" indicates the system table number.

The content of the previous applications 'and the ANO-2 application is essentially the' same.

The intent of the revised format used for the ANO-2 application was to' modify'the tables in

Chapter 3 to provide additional information to assist the staff in its review. In Table 1 the

applicant summarized the portions of the application it considered to be consistent with the

GALL Report. In Table 2, the applicant identified the linkage between the scoping and

screening results in Chapter 2 and the AMRs in Chapter 3.

3.0.1.1 Overviewf Table 1

Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the

corresponding tables of the GALL Report, Volume 1. The table is essentially the same as

Tables 1 through 6 provided in the GALL Report,' 'Type" Volume 1, except that the columr'has

been replaced by an "Item Number" column and the 'Item Number in GALL" column has been

replaced by a Discussion' column. The Wltdin Number' column provides the reviewer with a

means to cross-reference from Table 2 to Table 1. The "Discussiont column is used by the

applicant to provide clarifying/amplifying 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 being used

* Exceptions to the GALL Report as'surnptions

* A discussion of how the line is consistent with the corresponding line item in the GALL

Report when'that may not be intuitivelyobvious '

* A discussion of how the item is'different than the corresponding line item in the GALL

Report (e.g.'; when there is exception taken ito an aging management program that is'

listed in the GALL Report)

The format of Table 1 allows the staff to aliign a specific Tabl6'1 rowd with the corresponding

NUREG-1801', Volume'1, table row so that consistency can be checked easily:

3.0.1.2 Overview of Table2 2'

Table 2 provides the detailed results of the AMRs for those components identified in LRA

Section 2 as being subject to an AMR. The LRA contains a Table 2 for each of the components

or systems within a system grouping (e.g., reactor coolant systems, engineered safety features,

auxiliary systems, etc.). For exaimple,' the-engineefed safety features group contains tables

specific to the containment spray system,'containment isolation system, and emergency core

cooling system, Table'2 consists of the follo6inig nine columns: '

3-3
Component Tvpe - The first column identifies the component types from Section 2 of the LRA

that are subject to aging management review. They are listed in alphabetical order.

Intended Function - The second column contains the license renewal intended functions

(including abbreviations where applicable) for the listed component types. Definitions and

abbreviations of intended functions are contained within the Intended Functions table of LRA

Section 2.

Material - The third column lists the particular materials of construction for the component type.

Environment - The fourth column lists the environment to which the component types are

exposed. Internal and external service environments are indicated and a list of these

environments is provided in the Internal Service Environments and External Service

Environments tables of LRA Section 3.

Aging Effect Requiring Management - The fifth column lists aging effects requiring

management. As part of the aging management review process, the applicant determined any

aging effects requiring management for each material and environment combination.

Aging Management Programs - The sixth column lists the aging management programs the

applicant used to manage the identified aging effects.

GALL Vol: 2 Item - The seventh column lists the GALL Report item(s) that the applicant

identified as being similar to the AMR results in its LRA. The applicant compared each

combination of component type, material, environment, aging effect requiring management,

and aging management program in Table 2 of the SER to the items in the GALL Report. If

there were no corresponding item in the GALL Report, the applicant left the column blank. In

this way, the applicant identified the AMR results in the LRA tables that corresponded to items

in the GALL Report tables.

Table 1 Item - The eighth column lists the corresponding summary item number from Table 1.

If the applicant identifies AMR results in Table 2 that are consistent with the GALL Report, then

the associated Table 3.x.1 line summary item number should be listed in Table 2. If there is no

corresponding item in the GALL Report, then column eight is left blank. That way, the

information from the two tables can be correlated.

Notes - The ninth column lists the corresponding notes that the applicant used to identify how

the information in Table 2 aligns with the information in the GALL Report. The notes identified

by letters were developed by a Nuclear Energy Institute working group and will be used in future

license renewal applications. Any plant-specific notes are identified by a number and provide

additional information concerning the consistency of the line item with the GALL Report.

3.0.2 Staff's Review Process

The staff evaluated each row in Table 1 by moving from left to right across the table. Since the

applicant reproduced the component, aging effect/mechanism, aging management programs

and further evaluation recommended information from the SRP-LR, these table columns

required no further staff review. The staff reviewed information provided by the applicant in the

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Discussion column or other sections of the LRA to determine whether the applicant's AMR

results and AMPs were consistent with the AMRs and AMP items in the GALL Report.

The staff conducted the following three types of evaluations of the AMRs and associated AMPs.

* For items the applicant stated were consistent with the GALL Report or consistent with a

previously approved staff position, the staff conducted an audit.

* For items the applicant stated were consistent with the GALL Report with exceptions,

the staff conducted an audit and review of the item and of the applicant's technical

justification for the exceptions.

For other items, the staff conducted a technical review. Additionally, the staff conducted

a technical review for some items that were consistent with the GALL Report but

associated with emerging technical issues..-"

3.0.2.1 Review of AMPs

For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff

conducted an audit to confirm that the applicant's AMPs were consistent with the AMPs in the

GALL Report. -.

For each AMP that had one or more deviations,tthe staff evaluated each deviation to determine

(1) whether the deviation was acceptable, and (2) whether the AMP, as modified, would

adequately manage the aging effect(s) for .which it was credited.

For each AMP that was not evaluated in the GALL Report, the staff performed a full review to

determine the adequacy of the AMP.- The staff evaluated the AMP against the following 10

program elements defined in SRP-LR Appendix A.

1. Scope of program - Scope of the program should include the specific structures and.

components 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 functions(s).

4. Detection of aging effects - Detection of aging effects should occur before there is a loss

of structure or component intended functions(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,-and timely corrective or mitigative actions.

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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 a formal review and

approval process.

10. Operating experience - Operating experience of the aging management program,

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 managed adequately so that the structure and component intended

function(s) will be maintained during the period of extended operation.

The staff reviewed the applicant's corrective action program and documented its findings in

Section 3.0.3 of this SER. The staff's evaluation of the corrective action program included

assessment of the Corrective Actions, Confirmation Process, and Administrative Controls

program elements. Consequently, the staff's documentation of its review of AMPs not

consistent with the GALL Report AMPs only addresses 7 of the 10 program elements.

The staff reviewed the information concerning the operating experience program element for

the AMPs that are consistent with GALL Report AMPs. Details of the staff's evaluation of the

audit and review are documented in the ANO-2 Audit and Review Report.

The staff reviewed the Updated Final Safety Analysis Report (UFSAR) supplement for each

AMP to determine if it provided an adequate description of the program or activity, as required

by 10 CFR 54.21 (d).

3.0.2.2 Review of AMR Results

Table 2 of the LRA contains information concerning whether or not the AMRs align with the

AMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the

intended function, material, environment, aging effect requiring management and aging

management program combination for a particular component type within a system. The AMRs

that correlate between a combination in Table 2 and a combination in the GALL Report were

identified by a referenced item number in column seven, "GALL, Volume 2 Item." The staff

conducted an audit to determine the correlation. A blank column seven indicates that the

applicant was unable to locate an appropriate corresponding combination in the GALL Report.

The staff conducted a technical review of these combinations that were not consistent-with the

GALL Report. The next column, "Table 1 Item," provided a reference number that indicated the

corresponding row in Table 1.

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3.0.2.3 NRC-Approved Positions -'

To help facilitate the staff review of the LRA, an applicant may reference NRC-approved

positions to demonstrate that its non-GALL programs correspond to programs that the staff had

approved for other plants during its review of previous applications for license renewal. When

an applicant elects to proceed in this way , the staff determines whether the previously

approved position is applicable to the applicant's facility, determines whether the plant program

is bounded by the conditions for which the position was evaluated and approved, and

determines whether that the plant program contains the program elements (or attributes) of the

referenced NRC-approved position. In general, if the staff determines that these conditions are

satisfied, it will use the information in the previously approved position to frame and focus its

review of the applicant's program.

It is important to note that the reference information on previously approved positions provided

by the applicant is not a part of the LRA; it is supplementary information voluntarily provided by

the applicant as a reviewer's aid. The existence of a previously approved position, in and of

itself, is not a sufficient basis to accept the applicant's program. Rather, the previously

approved position facilitates the review of the substance of the matters described in the

applicant's program. As such, in the NRC staff's documentation of its reviews of programs that

are based on previously approved positions; the reference information is typically implicit in the

evaluation rather than explicit. If the staff determines that a previously approved position

identified by the applicant is not applicable to the particular plant program for which it is

-credited, it refers the program to the NRR, Division of Engineering (DE) for review in the

traditional manner, i.e., as described in the'SRP-LR, without consideration of the reference

information provided by the applicant. The applicant chose to provide reference information on

previously approved positions to support its selection of certain programs. Therefore, some of

the staff reviews documented in this SER considered the reference information in the manner

described above.

3.0.2.4 UFSAR Supplement

Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also

reviewed the UFSAR supplement that summarizes the applicant's programs and activities for

managing the effects of aging for the period of extended operation.

3.0.2.5 Documentation and Documents Reviewed - .

In performing its work, the staff relied heavily on the LRA, the SRP-LR, and the GALL Report.

The staff also examined the applicant's precedent review documents and AMP basis

-documents (a catalog of the documentation used by the applicant to develop or justify its

AMPs), and other applicant documents, including selected implementing procedures, to

determine that the applicant's activities and programs will adequately manage the effects-of -

aging on SCs.

Any discrepancies or issues discovered during the audit and review that required a formal

response on the docket are documented in the staff's ANO-2 Audit arid Review Report. If an

issue was resolved prior to issuing the Report, a request for additional information (RAI) was

prepared by the staff describing the issue and the information needed to disposition the issue.

The RAI, if needed, is included and dispositioned in this ANO-2 SER related to the LRA. The

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list of RAls associated with the audit and review is provided in Attachment 3 to the staff's ANO2 Audit and Review Report.

A list of documents reviewed by the staff is listed as Attachment 4 to the staff's ANO-2 Audit

and Review Report. During its site visits, the staff also conducted detailed discussions and

interviews with the applicant's license renewal project personnel and others with technical

expertise relevant to aging management.

3.0.3 Aging Management Programs

Table 3.0.3-1 presents the AMPs credited by the applicant and described in Appendix B of the

LRA. The table also indicates the GALL program that the applicant claimed its AMP was

consistent with (if applicable) and the systems, structures, or components that credit the

program for managing or monitoring aging. The section of the safety evaluation report in which

the staff's evaluation of the program is documented also is provided.

Table 3.0.3-1

ANO-2's Aging Management Programs

ANO-2's AMP GALL, GALL |LRA Systems or Structures Staffs (IRA Section) Comparison AMP(s) that Credit the AMP SER Section

Existing AMPs

Bolting and Torquing Plant-specific N/A Reactor Vessel, Intemals, 3.0.3.3.2

Activities Program and Reactor Coolant System;

(B.1.2) Engineered Safety Features

Systems; Auxiliary Systems; Steam and Power

Conversion Systems

Boric Acid Corrosion Consistent with XI.M10 Reactor Vessel, Internals, 3.0.3.2.1

Prevention Program enhancements and Reactor Coolant System;

(B.1.3) Engineered Safety Features

Systems; Auxiliary Systems; Structures and Component Supports; Electrical and

Instrumentation and Controls

Containment Leak Consistent Xl.S4 Engineered Safety Features 3.0.3.1

Rate Program (B.1.6) Systems; Structures and

Component Supports

Diesel Fuel Consistent with Xl.M30 Auxiliary Systems 3.0.3.2.3

Monitoring Program exceptions

(B.1.7)

Environmental Consistent X.E1 Electrical and 3.0.3.1

Qualification (EQ) of Instrumentation and Controls 3.6.2.1.4

Electric Components

Program (B.1.8)

Fatigue Monitoring Consistent with X.M1 Reactor Vessel, Internals, 3.0.3.2.4

Program (B.1.9) exceptions and Reactor Coolant System

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ANO-2's AMP GALL - GALL X LRASystems or Structures - Staff's

(LRA Section) Comparison ;: .-AMP(s) - that Credit the AMP SER Section

Fire Protection Consistent with XI.M26 Auxiliary Systems; Structures 3.0.3.2.5.1.

Program (8.1.10.1) exceptions and Component Supports

Fire Water System Consistent with Xl.M27. Auxiliary Systems; Structures 3.0.3.2.5.2

Program (B.1.10.2) one exception; and Component Supports .

one enhancement

Flow-Accelerated Consistent XI.M17 Reactor Vessel, Internals, 3.0.3.1

Corrosion Program . . and Reactor Coolant System;

(B.1.1 1) - . Engineered Safety Features

Systems; Auxiliary Systems;

Steam and Power

Conversion Systems

Inservice Inspection Plant-specific NIA Structures and Component 3.0.3.3.4

- Containment Supports

Inservice Inspection

(CII) Program

(B.1.13) ; .

Inservice Inspection Plant-specific N/A Reactor Vessel, Internals, 3.0.3.3.5

- Inservice . . and Reactor Coolant System;

Inspection (ISI) Structures and Component

Program (B.1.14) . Supports

Oil Analysis Program Plant-specific N/A Auxiliary Systems; Steam 3.0.3.3.6

(B.1.17) and Power Conversion

.- . . Systems .

Periodic Surveillance Plant-specific N/A Engineered Safety Features 3.0.3.3.7

and Preventive Systems; Auxiliary Systems;

Maintenance Steam and Power

Program (B.1.18) Conversion Systems; Structures and Component

Supports

Pressurizer Plant-specific N/A Reactor Vessel, Internals, 3.0.3.3.8

Examinations and Reactor Coolant System

Program (B.1.19) . . .

Reactor Vessel Head Consistent Xi.M1 1i Reactor Vessel, Intemals,, 3.0.3.1l

Penetration Program and Reactor Coolant System

(8.1 20) .

Reactor Vessel Consistent with XI.M31 Reactor Vessel, Internals, 3.0.3.2.6

Integrity Program enhancement . and Reactor Coolant System

(B.1.21) . . _ . ..:

Service Water Consistent with Xi.M20 Engineered Safety Features 3.0.3.2.7

Integrity Program exceptions/ .. . Systems; Auxiliary Systems;

(B.1.24) enhancement . Structures and Component

i_ __Supports

Steam Generator Consistent XI.M19 Reactor Vessel, Internals, 3.0.3.1

Integrity Program . . and Reactor Coolant System

(B.1.25) _

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ANO-2's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) that Credit the AMP SER Section

Structures Monitoring Consistent XI.S5 Structures and Component 3.0.3.1

- Masonry Wall Supports

Program (B.1.26)

Structures Monitoring Consistent XI.S6 Structures and Component 3.0.3.1

- Structures Supports

Monitoring Program

(B.1.27)

System Walkdown Plant-specific N/A Reactor Vessel, Intemals, 3.0.3.3.9

Program (B.1.28) and Reactor Coolant System;

Engineered Safety Features

Systems; Auxiliary Systems;

Steam and Power

Conversion Systems

Water Chemistry Plant-specific N/A Auxiliary Systems; Steam 3.0.3.3.11

Control - Auxiliary and Power Conversion

Systems Water Systems

Chemistry Control

Program (B.1.30.1)

Water Chemistry Consistent with XI.M21 Reactor Vessel, Internals, 3.0.3.2.8

Control - Closed exceptions and Reactor Coolant System;

Cooling Water Auxiliary Systems; Steam

Chemistry Control and Power Conversion

Program (B.1.30.2) Systems; Structures and

Component Supports

Water Chemistry Consistent XL.M2 Reactor Vessel, Internals, 3.0.3.1

Control - Primary and Reactor Coolant System;

and Secondary Engineered Safety Features

Water Chemistry Systems; Auxiliary Systems;

Control Program Steam and Power

(B.1.30.3) Conversion Systems;

Structures and Component Supports

New AMPs

Alloy 600 Aging Plant-specific N/A Reactor Vessel, Internals, 3.0.3.3.1

Management and Reactor Coolant System

Program (B.1.1)

Buried Piping Consistent with XI.M34 Auxiliary Systems 3.0.3.2.2

Inspection Program exceptions

(B.1.4)

Cast Austenitic Consistent XI.M12 Reactor Vessel, Intemals, 3.0.3.1

Stainless Steel and Reactor Coolant System

(CASS) Evaluation

Program (B.1.5)

Heat Exchanger Plant-specific N/A Engineered Safety Features 3.0.3.3.3

Monitoring Program Systems; Auxiliary Systems

(B.1.12)

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ANO-2's AMP GALL ;GALL ' LRA Systems or Structures Staff's'

(LRA Section) Comparison' AMP(s) ' -that t Credit the 'AMP SER Section

Non-EQ Inaccessible Consistent Xl.E3._ Electrical and ' 3.0.3.1

Medium-Voltage Instrumentation and Controls

Cable Program (B.1.15)

Non-EQ Insulated Consistent XI.E1 Electrical and 3.0.3.1

Cables and Instrumentation and Controls

Connections;

Program (B.1.16) - - -_I,,_'_'_.

Reactor Vessel Consistent XI.M13" Reactor Vessel, Internals, 3.0.3.1

Internals Cast - and Reactor Coolant System

Austenitic Stainless . Steel Components

Program (6.1.22)

Reactor Vessel Consistent XI.M16 Reactor Vessel, Intemals, 3.0.3.1

Internals Stainless ' and Reactor Coolant System

Steel Plates, I; , Forgings, Welds, and

Bolting Program I

(B.1.23) - - -: *_-

Wall Thinning Plant-specific N/A Auxiliary Systems 3.0.3.3.10

Monitoring Program

(B.1.29) ___

3.0.3.1 AMPs that are Consistent with the'GALL Report

In Appendix B of the LRA, the app!icant indicated that the following AMPs were consistent with

the GALL Report:

* Cast Austenitic Stainless Steel (CASS) Evaluation Program (B.1 .5)

* Containment Leak Rate Program (B.1.6)

* Environmental Qualification (EQ) of Electric Components Program (B.1.8)

* Flow-Accelerated Corrosion Prografn'(B.1.11)

* Non-EQ Inaccessible Medium-Voltage Cable Program (B.1.15)

* Non-EQ Insulated Cables and C 'h "' A ram (B.1.16)

* Reactor Vessel Head Penetration Prodgram (B.1.20)

* Reactor Vessel Internals Cast Austenitic Stainless Steel Components Program (B.1.22)

Reactor Vessel Internals Stainless Steel Plats, Forgings, Welds, and Bolting ProgramI

(B.1.23)

* Steam Generator Integrity Program'(B.1'.25)

* Structures Monitoring - Masonry Wall Program (B.1.26)

* Structures Monitoring - Structures Monitoring Program (B.1.27)

* Water Chemistry Control - Primary and Secondary Water Chemistry Control Program

(B.1.30.3)

During the audit that was conducted bythe staff'on December 1-5, 2003, the staff reviewed

selected documents and procedures associated with the AMPs that are listed ab6ve. , During

the technical review of the Reactor Vessel Internals Cast Austenitic Stainless Steel

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Components Program (B.1.22) and Reactor Vessel Internals Stainless Steel Plates, Forgings,

Welds, and Bolting Program (B.1.23), aspects pertaining to void swelling were under

development and not available for staff review. The applicant has committed to further

understanding of this aging effect through industry programs to provide additional bases for

supplemental examinations or component-specific evaluations.

3.0.3.1.1 Reactor Vessel Internal Programs

Since the details of the Reactor Vessel Internals Cast Austenitic Stainless Steel Components

Program have yet to be developed, including the details on location of components for

examination, inspection methods and qualifications, and frequency of examinations, the scope

of the AMP has yet to be finalized. The staff therefore issued RAI B.1.22-1 and requested that

the applicant formally make a commitment to submit a description of the program, including its

inspection plan, to the NRC staff for review and approval no later than three years prior to the

period of extended operation.

The applicant responded to RAI B.1.22-1 in a letter dated October 15, 2004. In this letter, the

applicant provided a commitment to submit a description of the Reactor Vessel Internals Cast

Austenitic Stainless Steel Components Program, including its inspection plan, to the NRC staff

for review and approval at least 24 months prior to entering the period of extended operation for

ANO-2.

The staff concludes that the following technical and regulatory bases justify the acceptance of

the Reactor Vessel Internals Cast Austenitic Stainless Steel Program, as discussed in Section

B.1.22 of the ANO-2 LRA and amended in the applicant's response to RAI B.1.22-1 dated

October 15, 2004:

1. The applicant will implement the AMP in accordance with the recommended guidance in

GALL AMP XI.M13, 'Thermal Aging and Neutron Irradiation Embrittlement of Cast

Austenitic Stainless Steel (CASS)."

2. The applicant has committed to submit a description of the aging management program,

including the inspection plan, for the RV internal CASS components for NRC review and

approval at least 24 months prior to entering the extended period of operation for

ANO-2. The staff has confirmed that the applicant has included this commitment in the

Commitment Tracking List for the ANO-2 LRA.

3. The applicant's commitment will provide the NRC with an opportunity to review the

inspection program for the RV internal CASS components and to resolve any potential

issues that may develop during the staff's review of the program. The staff considers 24

months to be sufficient evaluation time for reviewing the program and inspection plan

and for addressing any issues that may develop during the review process.

To obtain NRC staff approval its proposed inspection plan regarding CASS components prior to

entering the period of extended operation for ANO-2, the applicant must submit a license

amendment request. After the NRC staff's approval of the inspection plan, any future changes

to the inspection plan will be evaluate in accordance with 10 CFR 50.59.

3-12
Similarly, since the details of the Reactor Vessel Internals Stainless Steel Plates, Forgings,

Welds and Bolts Program have yet to be developed, including the details on location of

components for examination, inspection methods and qualifications, and frequency of

examinations, the scope of the AMP has yet to be finalized. The staff therefore issued RAI

B.1.23-1 and requested that the applicant formally make a commitment to submit a description

of the program, including its inspection plan, to the NRC for review and approval no later than

three years prior to the period of extended operation.

The applicant responded to RAI B.1.23-lin a letter, dated October 15, 2004. In this letter, the

applicant provided a commitment to submit a'description of the Reactor Vessel Internals

Stainless Steel Plates, Forgings, Welds, and Bolting Program, including the inspection plan,-to

the staff for review'and approval at least 24 months prior to entering the period of extended

operation for ANO-2.

The staff concludes that the following technical and regulatory bases justify the acceptance of

the Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program, as

discussed in Section B.1.23 of the ANO-2 LRA and amended in the applicant's responses to

RAI B.1.23-1 dated October 15, 2004:

1. The applicant will implement the AMP in accordance with the recommended guidance in

-GALL AMP XI.M16, -PWR Vessel Internals."

2. The applicant has committed to submit a description of the management program,

including the inspection plan; for the'RV internal stainless steel plate, forging; weld and

bolting components for NRC review and approval at least 24 months prior to' entering

the extended period of operation for ANO-2. The staff has confirmed that the applicant

has included this commitment in thb'Commitment Tracking List for the ANO-2 LRA.

3. The applicant's commitment will provide the NRC with an opportunity to review the

inspection program for the RV internal stainless steel plate, forging, weld and bolting

components and to resolve any potential issues that may develop during the staff's'

review of the program. The staff considers 24 months to be sufficient evaluation time

for reviewing the program and inspection plan and for addressing any issues that may

develop during the review process.

To obtain NRC staff approval its proposed inspection plan regarding Reactor Vessel Internals

prior to entering the period of extended operati6n for ANO-2, the applicant must submit a

license amendment request. After the NRC staff's approval of the inspection plan, any future

changes to the inspection plan will be evafluate in accordance with 10 CFR 50.59.

3.0.3.1.2 Reactor Vessel Head Penetration Program

The applicant credits the Reactor Vessel Head Penetration Program with the management of

cracking in the upper vessel head penetration (VHP) nozzles adjoined to the upper RV head for

ANO-2. -The applicant describes the React6r'Vessel Head Penetration AMP in LRA Section

B.1.20.' The applicant stated that the purpose of the Reactor Vessel Head Penetration AMP is

to manage PWSSC-induced cracking of the nickel-based alloy upper VHP nozzles to assure

that the p'ressure boundary function is maintained during the period of extended operation.

3-13
The applicant identified that the ANO-2 Reactor Vessel Head Penetration AMP is an existing

AMP whose program attributes are consistent with the comparable program attributes in GALL

AMP XI.M1 1, "Nickel-Alloy Nozzles and Penetrations," without any enhancements or

exceptions. The applicant also provided an applicable UFSAR Supplement summary

description for the Reactor Vessel Head Penetration AMP in Section A.2.1.21 of the ANO LRA.

Staff Evaluation

The staff evaluated the Reactor Vessel Head Penetration AMP against the corresponding

program elements in GALL AMP XI.M1 1, "Nickel-Alloy Nozzles and Penetrations." GALL

Section XI.M1 1 currently relies on the staff's original Alloy 600 inspection program

recommendations provided in GL 97-01, "Degradation of Control Rod Drive Mechanism Nozzle

and Other Vessel Head Penetrations," issued on April 1, 1997. However, between November

2000 and April 2001 and subsequent to the issuance of GL 97-01, reactor coolant pressure

boundary (RCPB) leakage was identified from the vessel head penetration (VHP) nozzles

adjoined to the upper RV heads of four U.S. PWR-design light water reactor facilities. In NRC

Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration

Nozzles," issued on August 3, 2001, the staff discussed the generic safety significance and

impacts of these cracks on RVH penetration nozzles and recommended that enhanced visual

examination or volumetric examination methods be used for the inspection of RVH penetration

nozzles. In March 2002, during a refueling outage at the Davis-Besse Nuclear Power Station,

the licensee for the plant reported the identification of reactor coolant leakage from RVH

penetration nozzles. On March 18,2002, the staff issued NRC Bulletin 2002-01, "Reactor

Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity," to

owners of PWR pressure vessels, requesting that the licensees address the impact of the

Davis-Besse event on the structural integrity of their RVHs and associated penetration nozzles.

On August 9, 2002, the staff issued NRC Bulletin 2002-02, "Reactor Pressure Vessel Head and

Vessel Head Penetration Nozzle Inspection Programs," to address additional technical issues

resulting from the Davis-Besse event. In NRC Bulletin 2002-02, the staff specifically suggested

that further augmented inspections, more comprehensive than those suggested in NRC Bulletin

2001-01, be performed on RV head penetration nozzles.

The applicant stated that the Corrective Action Program was used to incorporate industry

operating experience in order to develop inspections specific to ANO-2. Entergy Letter No.

OCAN040201, dated April 1, 2002, "1 5-Day Response to NRC Bulletin 2002-01, Reactor

Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity,"

provided Entergy's response to the NRC regarding potential VHP nozzle and RV head

degradation issues applicable to ANO-2. An assessment of the examination of ANO-2 upper

VHP nozzles was completed during refueling outage (RFO) No. 2R15 in 2002. This

assessment concluded that the examination of the ANO-2 upper VHP nozzles during RFO No.

2R15 was performed in accordance with the commitments stated in Entergy's response to NRC

Bulletin 2001 -01 for ANO-2.

On February 11, 2003, the NRC issued Order EA-03-009 to all holders of operating licenses for

pressurized light-water reactors (PWRs). This NRC order superceded NRC Bulletins 2001-01

and 2002-01, and required that licensees assess the susceptibility of the RV head to PWSCCrelated degradation. The Order also required licensees to perform augmented inspections for

the reactor pressure vessel head based upon the susceptibility to PWSCC. The NRC amended

EA-03-009 in a second order dated February 20, 2004, to more clearly define the applicable

3-14
requirements and to clarify which locations of the upper VHP nozzles were subject inspection

(henceforth NRC Order EA-03-009, as amended, Will be referred to as "the Order, as

amended"). The staff therefore included Entergy Operations Inc., (Entergy's) responses to the

Order, as amended, within the scope of its review of the ANO-2 Reactor Vessel Head

Penetration AMP.

In RAI B.1.20-1, the staff requested additional clarification on the status of the applicant's;

implementation of the Order, as amended, .for ANO-2. In response to RAI B.1.20-1, the

applicant stated that issues that are relevant to current plant operation are being addressed by

the existing regulatory process within the present license term rather than deferred until the

time of license renewal. -Consequently, the existing regulatory process provides assurance that

ongoing interaction between Entergy and the NRC staff is occurring to ensure appropriate

measures are included in the Reactor Vessel Head Penetration Program in response to the

Order, as amended, and subsequent relevant industry experience and regulatory requirements.

In addition, the applicant stated that the Reactor Vessel Head Penetration Program identifies

both visual and volumetric examination in accordance with the requirements of the Order, as

amended, and will be modified as appropriate toinclude measures taken to implement evolving

commitments in response to industry experience and regulatory requirements. - -

The actions that were required by the Order, as amended, have been evaluated by the staff.

The bases for the staff's acceptance of the applicant's request for relaxation of certain

requirements of the Order, as amended, are provided in NRC safety evaluations dated October

2, 2003 (Vent Line Nozzle Relaxation Approval),! October 9, 2003 (CEDM Nozzles Relaxation

Approval), October 9, 2003 (Incore Instrumentation Nozzles Relaxation Approval), and October

9, 2003 (Bare Metal Visual Relaxation Approval). Therefore, the staff finds the applicant's

response to RAI B.1.20-1 and the applicant's Reactor Vessel Head Penetration AMP are

acceptable and considers this issue closed.

FSAR Supplement

The applicant provided the following UFSAR Supplement summary description for the Reactor

Vessel Head Penetration Program in Section A.2.1.21 of the ANO-2 LRA:

The Reactor Vessel Head Penetration Program manages cracking of nickel

based alloy reactor vessel head penetrations exposed to borated water to assure

that the pressure boundary function is maintained. The program consists of both

visual and volumetric examinations in accordance with NRC Order EA-03-009.

In addition, the program includes ANO-2 commitments in response to NRC

Generic Letter 97-01. The program will be modified as appropriate to implement

evolving commitments in response to industry experience and regulatory

requirements. The Inservice Inspection (Section A.2.1.15) and Water Chemistry

Control Programs (Section A.2.1.33) are used in conjunction with this program to

manage cracking of the reactor vessel head penetrations.

The applicant's FSAR Supplement summary description for the Reactor Vessel Head

Penetration Program is consistent the applicant's obligations imposed by the Order, as

amended. Since the FSAR Supplement summary description is current with the CLB for the

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facility, the staff finds the FSAR Supplement summary description for the Reactor Vessel head

Penetration Program to be acceptable.

Conclusion

The staff has reviewed the Reactor Vessel Head Penetration Program, as discussed in Section

B.1.20 of the ANO-2 LRA. On the basis of its review of the applicant's program, as described

above, the staff finds that those portions of the program for which the applicant claims

consistency with the GALL program are consistent with the GALL program. In addition, for the

reasons set forth above, the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR Supplement summary description for this AMP, as

described in Section A.2.1.21 of the ANO-2 LRA, and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

For all the other AMP's reviewed in this section, the staff confirmed the applicant's claim of

consistency. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. The staff determined that these AMPs are consistent with the

AMPs described in the GALL Report, including the associated operating experience attribute.

In Appendix A of the LRA, the applicant provided the Updated Final Safety Analysis Report

(UFSAR) supplement required by 10 CFR 54.21 (d). The applicant will incorporate the

information presented in Appendix A into the UFSAR as Chapter 18 following the issuance of

the renewed operating licenses. The staff reviewed the information in Appendix A and verified

that the information in the UFSAR supplement provides an adequate summary of the program

activities. The staff reviewed the following sections of Appendix A of the LRA.

* Section A.2.1.5 of the LRA for the Cast Austenitic Stainless Steel (CASS) Evaluation

Program

* Section A.2.1.6 of the LRA for the Containment Leak Rate Program

* Section A.2.1.8 of the LRA for the Environmental Qualification (EQ) of Electric

Components Program

* Section A.2.1.12 of the LRA for the Flow-Accelerated Corrosion Program

* Section A.2.1.16 of the LRA for the Non-EQ Inaccessible Medium-Voltage Cable

Program

* Section A.2.1.17 of the LRA for the Non-EQ Insulated Cables and Connections Program

* Section A.2.1.21 of the LRA for the Reactor Vessel Head Penetration Program

* Section A.2.1.23 of the LRA for the Reactor Vessel Internals Cast Austenitic Stainless

Steel Components Program

3-16

I
* Section A.2.1.24 of the LRA for the Reactor Vessel Internals Stainless Steel Plates,

Forgings, Welds, and Bolting Program

* Section A.2.1.26 of the LRA for the Steam Generator Integrity Program

* Section A.2.1.27 of the LRA for the Structures Monitoring - Masonry Wall Program . ~,

* Section A.2.1.28 of the LRA for the Structures Monitoring - Structures Monitoring

Program 'x¢

* Section A.2.1.33 of the LRA for the Water Chemistry Control - Primary and Secondary

Water Chemistry Control Program

The applicant provided the following UFSAR Supplement summary description for the Reactor

Vessel Internal Cast Austenitic Stainless Components AMP in Section A.2.1.23 of the ANO-2

LRA:

The Reactor Vessel Internals Cast Austenitic Stainless Steel (CASS) Program will

manage aging effects of cast austenitic stainless steel reactor vessel internals

components. This program will supplement the reactor vessel internals inspections

required by the ASME Section Xl Inservice Inspection Program. The program will

manage cracking, reduction of fracture toughness, and dimensional changes using

inspections of applicable components which will be determined based on the neutron

fluence and thermal embrittlement susceptibility of the component. The Reactor Vessel

Internals Cast Austenitic Stainless Steel Program will be initiated prior to the period of

extended operation.

The applicant provided the following UFSAR Supplement summary description for the Reactor

Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program in Section

A.2.1.24 of the ANO-2 LRA:

The Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and

Bolting Program will manage aging effects of reactor vessel internals plates,

forgings, welds, and bolting. This program will supplement the reactor vessel

internals inspections required by the ASME Section XI Inservice Inspection

Program. This program will manage the effects of crack initiation and growth

due to stress corrosion cracking or irradiation assisted stress corrosion cracking,

loss of fracture toughness due to neutron irradiation embrittlement, and distortion

due to void swelling. This program will provide visual inspections and nondestructive examinations of reactor vessel internals. The Reactor Vessel

Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program will be

initiated prior to the period of extended operation.

The staff noted that the water chemistry system and the enhanced examination of non-bolted

components are not discussed In LRA UFSAR Supplement, Section A.2.1.24 as is

recommended in NUREG-1 800, Table 3.1-2, page 3.1-27, for GALL AMP XI.M16, "PWR

Vessel Internals." In RAI B.1.23-2, the staff requested that the applicant revise LRA Section

A.2.1.24 to be consistent with Table 3.1-2 of NUREG-1800 (page 3.1-27).

3-17
M

In response to RAI B.1.23-2 the applicant stated that control of ANO-2 primary water chemistry

in accordance with the appropriate EPRI guidelines is discussed in the Water Chemistry Control

Program section of the UFSAR Supplement, Section A.2.1.33. As indicated in LRA Table

3.1.2-2, the Water Chemistry Control Program applies to reactor vessel internals items.

Therefore, UFSAR Supplement Section A.2.1.33. is an acceptable alternative summary

description for describing the mitigative effect of the Water Chemistry Program on potential

corrosive degradation mechanisms for the RV internal components.

On the basis of its audit, the staff finds that those programs for which the applicant claimed

consistency with the GALL Report are consistent with the AMPs described in the GALL Report.

Details of the staff's evaluation of the audit and review are documented in the ANO-2 Audit and

Review Report.

The staff concludes that for the AMPs listed above, the applicant has demonstrated that the

effects of aging can be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff reviewed the associated UFSAR supplements for these AMPs

and concludes that the UFSAR supplements provide an adequate summary description of the

programs, as required by 10 CFR 54.21 (d).

3-18
3.0.3.2 AMPs that are Consistent with the GALL heport with Exceptions and/or Enhancements

In Appendix B of the LRA, the applicant indicated that the following AMPs were consistent with

the GALL Report with exceptions and/or enhancement.

* Boric Acid Corrosion Prevention Program (B.1.3)

* Buried Piping Inspection Program (B.1.4)

* Diesel Fuel Monitoring Program (B.1.7)

* Fatigue Monitoring Program (B.1.9)

* Fire Protection and Fire Water System Program (B.1.1 0.1 and B.1.1 0.2)

* Reactor Vessel Integrity Program (B.1.21)

* ' 'Service Water Integrity Program (B.1.24) -

* Water Chemistry Control - Closed Cooling Water Chemistry Control Program' (B.1.30.2)

For AMPs that the applicant claimed are consistent with the GALL Report with exceptions

and/or enhancement, the staff performed an audit to determine whether those' elements or

features of the program for which the' appiicant claimed consistency with thbe' GALL Report were

indeed consistent. 'Furthermore, the staff reviewed the exceptions and/or enhancement and its

justification to determine'whether the AMP, with the exceptions and/or enhancement,' remains

adequate to manage the aging effects for which it is credited. Details of the staff's evaluation of

the audit and review are documented in the ANO-2 Audit and Review Report. The staff also

reviewed the exceptions and/or enhancements to the GALL Report to determine whether they

were acceptable.' The results of the staff'6 audita'nd review are documented in the'following

sections of this SER.

3.0.3.2.1 Boric Acid Corrosion Prevention Program

Summarv of Technical Information

The applicant credits the Boric Acid Corrosionr Prevention Program with aging management of

boric acid-induced corrosion of carbon steel and low alloy steel components and discusses this

program is Section B.1.3 of the ANO-2 LRA. The applicant identified this 'program as a

program that was consistent with the GALL- Report and stated that this program was consistent

with the corresponding program discussed in; GALL AMP XI.M1 0, "Boric Acid Corrosion," with'-

the following enhancements:,

* The program scope will be revised to include identification and evaluation of the effects

of borated water leakage on electrical components in addition'to ferritic steel.'

* The program'acceptance criteria Will be revised to address electrical components in

addition to ferritic steel.

The applicant also include an applicable UFSAR Supplement summary description for the Boric

Acid Corrosion Prevention Program in Section A.2.1.3 of the ANO-2 LRA.

Staff Evaluation

The staff reviewed the information provided in Section B.1.3 of Appendix B to the LRA and

compared the program description for the Boric Acid Corrosion Prevention Program to the 10

(3119
program elements in GALL AMP XI.M10, 'Boric Acid Corrosion," which provide detailed

programmatic characteristics and criteria that the staff considers to be necessary to manage

boric acid-induced corrosion of low alloy steel and carbon steel RCS components.

In RAI B.1.3-1, the staff requested that the applicant provide the basis for the proposed

acceptance criteria that will be developed as part of the following enhancement to the Boric

Acid Corrosion Prevention AMP:

* The program scope will be revised to include identification and evaluation of the effects

of borated water leakage on electrical components in addition to ferritic steel.

* The program acceptance criteria will be revised to address electrical components in

addition to ferritic steel. .

In response to RAI B.1.3-1, the applicant stated that NUREG-1801 will be the basis for the

acceptance criteria for electrical components exposed to boric acid. In accordance with

"Acceptance Criteria" of NUREG-1 801, Section Xl.M10, acceptance criteria will be the absence

of any detected leakage or crystal buildup. If identified during inspections, evidence of leakage

or crystal buildup will be evaluated to determine the need for corrective actions prior to

continued service. The acceptance criteria will apply to electrical components as well as ferritic

steel components. The staff finds the response acceptable and considers this issue closed.

The applicant retains the program description of the Boric Acid Corrosion Prevention Program,

as well as the descriptions of the program's 10 elements, on record at the ANO-2 facility.

Operating Experience

In the Operating Experience Section of B.1.3, Boric Acid Corrosion Prevention, the applicant

states that recent industry events regarding RV head degradation required assessments at

each ANO site to ensure that the Boric Acid Corrosion Prevention Programs for ANO-1 and

ANO-2 are adequate and functioning effectively. The applicant also states that a self

assessment was performed in February 2003, and no significant findings were identified during

this assessment. In RAI B.1.3-2, the staff requested additional information on how program

revisions have incorporated lessons learned from the Davis Besse vessel head degradation and

the control rod drive mechanism penetration cracking discussed in Bulletins 2001-01, 2002-01,

2002-02, and Order EA-03-009. The staff also requested a discussion on implementation of

corrective actions in the program which would prevent reoccurrences of degradation caused by

boric acid leakage, as addressed in Generic Letter 88-05.

In response to B.1.3-2 the applicant stated that the Boric Acid Corrosion Prevention Program

addresses the loss of material of carbon and low-alloy steel components exposed to a treated

(borated) water environment. An assessment performed in 2003 concluded that the ANO-2

Boric Acid Corrosion Prevention Program was sufficient to detect loss of material by boric acid

wastage of the RV head in the event of leaking CEDM penetrations. However, ANO-2 does not

rely on leak detection through the Boric Acid Corrosion Prevention Program to manage

cracking of CEOM penetrations. The ANO-2 Reactor Vessel Head Penetration Program

described in Section B.1.20 of the LRA addresses RV head degradation and CEDM penetration

cracking as discussed in the referenced NRC Bulletins and NRC Order EA-03-009. Measures

3-20

I
taken in response to'NRC Order EA-03-009 and its successors carry forward into the period of

extended operation.

The applicant also stated that the ANO-2 Boric Acid Corrosion Prevention Program is

consistent with NUREG-1 801, Section XI.M.10 and ANO-2 commitments in response to NRC

Generic Letter 88-05. ANO-2 applies the requirements of 10 CFR 50, Appendix B to the Boric

Acid Corrosion Prevention Program through the ANO-2 Corrective Action Program.

It should be noted that NRC Bulletin 2004-01 ulnspection of Alloy 82/182/600 Materials Used in

the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at

Pressurized-Water Reactors," was issued on May 28, 2004. Bulletin 2004-01 summarizes

industry experience, and has demonstrated that Alloy 600 base metal and Alloy 82/182 weld

components used in pressurizer penetration nozzles and steam space piping connections may

be susceptible to PWSCC and consequential reactor coolant leakage.

The staff and the industry are currently pursuing resolution of the issues raised and discussed

in NRC Bulletin 2004-01 on PWSCC and reactor coolant leakage in pressurizer penetration

nozzles and steam space piping connections. Because this is an emerging issue that has yet

to be resolved, but will be resolved during the current operating terms for ANO-2, consideration

of these issues is beyond the scope of this license renewal review, pursuant to 10

CFR54.30(b).

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.3 adequately manages the aging

effects that have been observed at the applicant's plant.

UFSAR SupDlement

The applicant provided the following UFSAR Supplement summary description for the Boric

Acid Corrosion Prevention Program in Section A.2.1.3 of the ANO-2 LRA:

The Boric Acid Corrosion Prevention Program relies on implementation of

recommendations of NRC Generic Letter (GL) 88-05 to monitor the condition of ferritic

steel and electrical components on which borated water may leak. The program will -

detect borated water leakage by periodic visual inspection of borated water containing

systems for deposits of boric acid crystals and the presence of moisture. This program

will manage loss of material, loss of mechanical closure integrity, and corrosion of

connector surfaces.

The applicant's program description for the Boric Acid Corrosion Prevention Program is

consistent with the corresponding FSAR Supplement summary description for GALL AMP

XL.M1O, uBoric Acid Corrosion," as described in Table 3.1-2 of the SRP-LR, and is therefore

acceptable.

Conclusion

The staff has reviewed the Boric Acid Corrosion Prevention Program, as discussed in Section

B.1.3 of the ANO-2 LRA:. The staff finds this AMP. acceptable because the program has been

effectively managing aging effects in all applicable SSCs constructed of carbon steel, low-alloy

steel, and other susceptible materials that may be affected by borated water leakage. On the

3-21
basis of its review of the applicant's program, the staff finds that those portions of the for which

the applicant claims consistency with the GALL program are consistent with the GALL program.

In addition, the staff has reviewed the enhancements to the GALL program and finds that the

applicant has demonstrated that the effects of aging can be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR Supplement summary description for this AMP, as

described in Section A.2.1.3 of the ANO-2 LRA, and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.2 Buried Piping Inspection

Summary of Technical Information in the Application

The applicant's buried piping inspection program is described in LRA Section B.1.4, 'Buried

Piping Inspection." In the LRA, the applicant stated that this is a new program that will be

initiated prior to the period of extended operation. This program will be consistent, with

exceptions, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection." This AMP is

credited with preventive measures to mitigate corrosion and with inspections to manage the

effects of corrosion on the pressure-retaining capability of buried carbon steel components.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. Furthermore, the staff reviewed the exceptions and their

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In Appendix B, Section B.1.4, of the LRA, the applicant stated that the buried piping 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

components. Preventive measures will be in accordance with standard industry practice for

maintaining external coatings and wrappings. Buried components will be inspected when

excavated during maintenance. With the following exceptions, which will be initiated prior to the

period of extended operation, the applicant stated that the buried piping inspection program will

be consistent with GALL AMP XI.M34:

Element: 1: Scope of Program

Exception: (1) Buried valves and bolting that are not included in the GALL AMP will be

inspected as part of this AMP.

(2) Tanks will not be inspected.

Element: 4: Detection of Aging Effects

Exception: Buried components will be inspected only when excavated during maintenance

activities, not based on a scheduled inspection frequency.

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In the LRA, the applicant stated the buried piping inspection program will include buried valves

and bolting that are not included in the GALL AMP. The applicant stated that the additional

components are of the same material, exposed to the same environment, and are expected to

have the same aging effects as the other components covered by this AMP. Thus, the effects

of aging will be identified prior to loss of intended function regardless of component type. In

addition, the applicant stated that there are no buried tanks subject to an AMR.

In addition, the buried piping inspection program will require inspections of the buried

components only when excavated during maintenance activities, which is inconsistent with the

GALL AMP. The applicant stated that excavating such components solely to perform

inspections poses undue risk of damage to protective coatings. Operating experience shows

that the'frequency of excavating buried components for maintenance activities is sufficient to

provide assurance that the effects of aging will be identified prior to loss of intended function.

The staff finds that including the buried valves and bolting within the program scope is

acceptable because they are the same material, exposed to the same environment, and are

expected to have the same aging effects as the carbon steel piping covered by the buried

piping inspection program. Because none of the ANO-2 buried tanks are within the scope of

license renewal and subject to an AMR, the staff finds excluding buried tanks for inspection to

be acceptable as well.

The GALL Report program description in Section XI.M34 recommends further evaluation of an

applicant's operating experience with buried components in determinations of the adequacy of.

this program element. The staff reviewed the ANO-2 operating experience with excavations

over the past few years and, based on the review as well as the applicant's discussion of this

exception in the LRA, the staff finds that the frequency of excavating buried components for

maintenance activities will be sufficient to provide assurance that the effects of aging will be'

identified prior to loss of intended function. Excavating such components solely to perform

inspections could pose undue risk of damage to protective coatings. The staff finds that this.

exception is acceptable.

On the basis of its review of this AMP, the associated engineering report, and the operating

experience, the staff determined that the buried piping inspection program is consistent with the

GALL Report and that the exceptions in the buried piping inspection program are acceptable.

Operating Experience

The applicant stated that there have been multiple excavations at the site which provide some

plant-specific operating experience even though the buried piping inspection program is a new

program.

The staff reviewed the documentation for multiple excavations performed at the site for several

maintenance activities. These excavations indicate that corrosion has not been a problem.

During the audit, the staff asked the applicant to clarify and/or provide the operating experience

reviews for new programs. In its response, the applicant stated that the plant corrective action

program,-which captures internal and external plant operating experience issues, provides

assurance that operating experience will be reviewed and incorporated in the future to provide'

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objective evidence to support the conclusion that the effects of aging will be adequately

managed.

On the basis of its review of the above operating experience and the applicant's response, and

on discussions with the applicant's technical staff, the staff concludes that the buried piping

inspection program will adequately manage the aging effects that have been observed at the

applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.4, of the LRA, the applicant provided the UFSAR supplement for

the buried piping inspection program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the program activities.

The staff finds this section of the UFSAR supplement sufficient.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL Report

program are consistent with the GALL Report program. In addition, the staff has reviewed the

exceptions to the GALL Report program and finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.3 Diesel Fuel Monitoring

Summary of Technical Information in the Application

The applicant's diesel fuel monitoring program is described in LRA Section B.1.7, "Diesel Fuel

Monitoring." In the LRA, the applicant stated that the program is consistent with, but includes

exceptions to, GALL AMP XI.M30, "Fuel Oil Chemistry Program." This AMP is credited with

ensuring that adequate diesel fuel quality is maintained to prevent plugging of filters, fouling of

injectors, and corrosion of the fuel systems.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. Furthermore, the staff reviewed the exceptions and their

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In Appendix B, Section B.1.7, of the LRA, the applicant stated the following exceptions to GALL

AMP XL.M30:

3-24

I
Element:

Exception:

Elements:

Exceptions:

I .

Element:

Exception:

2: Preventive Actions

No additives are used (other than biocide) beyond what the refiner adds during

production.-

3: Parameters Monitored/inspected

6: Acceptance Criteria ,

-(1) Only American Society for Testing Materials (ASTM) standard D 1796 is

used for determination of water and sediment, rather than standards

D 1796 and D 2709.,

(2). The LRA AMP specifies the method of ASTM standard D 2276 with 0.8

prm filter, instead of the modified ASTM standard D 2276, Method A, with

a 3 pm filter.

4: Detection of Aging Effects,

The program does not include ultrasonic measurements of tank bottoms.

The GALL Report identifies the following criterion for the preventive actions program element

associated with the exception taken:

The quality of fuel oil is maintained by additions of biocides to.minimize biological

activity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion

inhibitors to mitigate corrosion. 2

The applicant stated that the #2 diesel fuel used at ANO-2 contains a comprehensive additive

package. On the basis of its review of operating experience for the ANO-2 diesel fuel

monitoring program (see discussion below);:the staff finds this exception to be acceptable.

The GALL Report recommended the following criteria: (1) ASTM standard D 4057 is used for

guidance on oil sampling and (2) ASTM standards D 1796 and D 2709 are used for

determination of water and sediment contamination in diesel fuel. The staff determined that of

the three standards recommended by the GALL Report, only the guidance presented in ASTM

standard D 1796 applies to fuel oils with the viscosity of that used at ANO-2, and therefore finds

this exception to be acceptable.

The guidance in the GALL Report concerning the use of modified ASTM standard D 2276,

Method A, recommends a maximum pore size for determination of particulates. Use of a filter

with a smaller pore size would not increase the likelihood that aging effects would go

undetected and thus potentially affect the ability of components to perform their intended

functions consistent with the CLB during the period of extended operation. The staff finds that

the applicant's use of ASTM standard D 2276, which specifies the use of a filter with a smaller

0.8,pm pore size than that recommended in ASTM standard D 2276, Method A, is acceptable

since the use of a 0.8 pm filter is more conservative than use of the 3.0 pm filter specified in the

GALL Report.

The GALL Report states that corrosion may occur at locations in which contaminants may

accumulate, such as a tank bottom, and an ultrasonic thickness measurement of the tank

bottom surface ensures that significant degradation is not occurring.

. .~!.ir. ,v,.:

3-25
The staff reviewed recent fuel oil operating experience and determined that compliance with

diesel fuel oil standards and periodic sampling provide assurance that fuel oil contaminants that

cause degradation are below allowable limits. Specifically, the review of recent operating

experience did not identify unacceptable levels of water, particulate contamination, or biological

fouling in the fuel oil. A review of condition reports did not identify instances of fuel oil system

component failures attributed to the condition of the fuel oil. Condition report trending data did

not identify a need for improvements to this program. Quarterly assessments are performed to

review diesel fuel quality parameters to ensure that acceptance criteria are being met and to

identify early indications of problems. In addition, the applicant stated that internal surfaces of

tanks that are drained for cleaning are visually inspected for degradation. Based on the above

discussion, the staff finds that the exception to preclude ultrasonic measurements of tank

bottoms is acceptable.

On the basis of its review of this AMP, the associated engineering report, and the operating

experience, the staff determined that this AMP is consistent with the GALL Report and that the

exceptions in the diesel fuel monitoring program are acceptable.

Operating Experience

The staff reviewed the operating experience for the diesel fuel monitoring program. The

applicant stated that it had experienced fuel oil related problems in 1986. Significant program

improvements were implemented as a result of these events. One of the recommendations

addressed the addition of an oxidation inhibitor to stored fuel. This is consistent with the need

for adding corrosion inhibitors.

The staff's review of recent operating experience did not identify unacceptable levels of water,

particulate contamination, or biological fouling in the fuel oil. A review of condition reports did

not identify instances of fuel oil system component failures attributed to the condition of the fuel

oil. Condition report trending data did not identify a need for improvements to this program. In

addition, the applicant stated that it will perform quarterly assessments to review diesel fuel

quality parameters to ensure that acceptance criteria are being met and to identify early

indications of problems.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that diesel fuel monitoring program adequately

manages the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.7, of the LRA, the applicant provided the UFSAR supplement for

the diesel fuel monitoring program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the program activities.

The staff finds this section of the UFSAR supplement sufficient.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL Report

program are consistent with the GALL Report program. In addition, the staff has reviewed the

3-26
exceptions to the GALL Report program and finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.4 Fatigue Monitoring Program

Summary of Technical Information in the Application

The applicant's fatigue monitoring program is described in LRA Section B.1.9, 'Fatigue

Monitoring." In the LRA, the applicant stated that the program is consistent with, but includes

exceptions to, GALL-AMP XI.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." This

AMP is credited with tracking the number of critical thermal and pressure transients for selected

reactor coolant system components. ,

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. 'Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. -Furthermore, the staff reviewed the exceptions and their -: -

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In Appendix B, Section B.1.9, of the LRA, the applicant stated the following exceptions to GALL

AMP XI.M1:

Element: 2: Preventive Actions

Exception: The program only involves tracking the number of transient cycles.

Element: 4: Detection of Aging Effects

Exception: The program does not provide for periodic update of fatigue usage calculations.

-Corrective actions are initiated only when the number of accumulated cycles

approaches the number of component design cycles.,

The GALL Report states that maintaining the fatigue usage factor below the design code limit

and considering the effect of the reactor water environment will provide adequate margin '-

against fatigue cracking of RCS components due to anticipated cyclic strains.

The effect of the reactor water environment on'fatigue is addressed as a TLAA in the LRA,

Section 4.3.3.1 (Generic Safety Issue 190).. The staff's evaluation of this is addressed in

Section 4 of this SER.

The GALL Report states that the program provides for periodic update of the fatigue usage

calculations. The applicaint'stated that'updates of fatigue usage calculations, as recommended

in the GALL Report, are not necessary unless the number of accumulated fatigue -cycles

approaches the number of assumed design cycles, and commits to implement corrective

3-27
actions at that time. This is an alternative method for ensuring that the design code limit is not

exceeded.

On the basis of its review of this AMP, the associated engineering report, and the operating

experience, the staff determined that this AMP is consistent with the GALL Report and that the

exceptions in the fatigue monitoring program are acceptable.

Operating Experience

The staff reviewed operating experience for the fatigue monitoring program. The applicant

issues quarterly reports documenting operating history, the total number of critical types of

transients, and the design limits. Condition report trending data does not reveal a need for

improvements to this program. The number of pressure and temperature transient cycles is

monitored and periodically compared with the design cycle count, as required by the program,

to ensure that fatigue-sensitive components do not exceed their allowable number of design

cycles. Based on the above discussion, the staff finds the exception to preclude the periodic

update of fatigue usage calculations and that corrective actions are initiated only when the

number of accumulated cycles approaches the number of component design cycles to be

acceptable.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.9 is sufficient to support the

management of the aging effects of fatigue that has been monitored and predicted at the

applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.9, of the LRA, the applicant provided the UFSAR supplement for

the fatigue monitoring program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the program activities.

The staff finds this section of the UFSAR supplement sufficient.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL program

are consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.5 Fire Protection Program

The applicant's fire protection program is described in LRA Section B.1.10, "Fire Protection."

The AMP comprises two programs: Fire Protection and Fire Water System. Each program is

discussed below.

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3.0.3.2.5.1 Fire Protection

Summary of Technical Information in the Application

The applicant's fire protection is described in LRA Section B.1.10.1, "Fire Protection."- In the

LRA, the applicant stated that the program is consistent with, but includes exceptions to, GALL

program XI.M26, -Fire Protection." This AMP is credited with performing periodic inspections,

and functional tests of the fire barriers and a diesel-driven fire pump to ensure that the

operability of the fire barriers is maintained and that the fire pump fuel supply line can perform

the intended function, respectively.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. Furthermore, the staff reviewed the exceptions and their

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In Appendix B, Section B.1.10.1, of the LRA, the applicant stated the following exceptions to

GALL AMP XI.M26:

Element: :3: Parameters Monitored/lnspectedExceptions: (1) Fire doors are inspected and clearances checked annually, not

bi-monthly. - ... . ,

(2) Function tests of fire doors are performed annually, not daily, weekly, or

monthly.

Elements: 1: Scope

3: Parameters Monitored/inspected ..

4: Detection of Aging Effects

5: Monitoring and Trending

6: Acceptance Criteria -

Exception: -.:This program is not necessary to manage aging effects on halon fire protectionsystem components. - :

The GALL Report identifies the following criteria for the parameters monitored/inspected

program element associated with those exceptions taken:

- Hollow metal fire doors are visually inspected at least once bimonthly for holes

in the skin of the door.:. Fire door, clearances are also checked at least once

bimonthly as part of an inspection'program.

Function tests of fire doors are performed daily, weekly, or monthly (which may

be plant-specific) to determine the operability of automatic hold-open, release,

closing mechanisms, and latches.,. . .. *¢ o r;.I.w *. 

i3-29
a

The applicant stated that inspection intervals are determined by engineering evaluation to

detect degradation of the fire doors prior to the loss of intended function. Interim Staff

Guidance (ISG) 04 revised criteria for the GALL AMP XL.M26 parameters monitored/inspected

program element to no longer require fire doors to be visually inspected or function tested on a

specific frequency. Rather, the applicant can establish a plant-specific interval to determine

whether the integrity of door surfaces and for clearances, with plant-specific inspection intervals

to be determined by engineering evaluation to detect degradation of the fire doors. The

applicant's program meets ISG-04. Therefore, the staff finds this exception to be acceptable.

The GALL Report identifies the following criteria for program elements: scope, parameters

monitored/inspected, detection of aging effects, monitoring and trending, and acceptance

criteria. These criteria are associated with the exception that the fire protection program is not

necessary to manage the aging effects on halon fire protection system components:

(1) The scope of this program includes the management of the aging effects on the

intended function of the halon/carbon dioxide fire suppression system.

(2) Periodic visual inspection and function tests are to be performed at least once every six

months to examine the signs of degradation of the halon/carbon dioxide fire suppression

system.

In LRA Section 3.3.2.1.6 and Table 3.3.2-6, the staff reviewed the halon fire protection and

reactor coolant pump motor oil leakage collection system AMR. The applicant credited the

periodic surveillance and preventive maintenance program with managing the aging effect of

loss of material for the halon fire protection system components. The applicant credited the

periodic surveillance and preventive maintenance and boric acid corrosion programs with

managing the aging effect of loss of material for the RCP motor oil leakage collection system.

The staff reviewed the periodic surveillance and preventive maintenance program and finds that

its scope includes aging management of components in the halon fire protection and RCP

motor oil leakage collection system.

On the basis of its review of the applicant's programs, the staff finds that the boric acid

corrosion program and periodic surveillance and preventive maintenance program effectively

manage the aging effect of loss of material on halon fire protection system components so that

their intended functions will be maintained during the period of extended operation.

The staff concludes that the periodic surveillance and preventive maintenance program, in lieu

of the fire protection program, adequately manage the aging effects of halon and RCP motor oil

leakage collection system components during the period of extended operation.

On November 1 through 5 and 15 through 19, 2004, the NRC staff performed an AMP

inspection at ANO-2. During the inspection, the NRC staff noted that replacement components

for valve 2CV-5017-1 stored in the warehouse and required for cold shutdown repair were not

included in the scope of license renewal. The inspection staff believed that these components

should be in-scope for license renewal and referred to NRR for guidance.

NRR staff evaluated the post-fire cold shutdown replacement components (stem clamp key,

stem clamp, set screw) for Low Pressure Safety Injection Valve 2CV-5017-1. During the ANO2 - NRC License Renewal Aging Management Review Inspection (NRC Inspection Report

05000368/2004-007), conducted November 1-5, 2004, and November 15-19, 2004, the

3-30
inspectors questioned whether the components should be within the scope of license renewal

since the components are safety-related, relied onto perform a function that demonstrates

compliance with 10 CFR 50.48, and the status of the components staged in the warehouse for

10 CFR 50.48 use is passive. In response, the applicant conservatively elected to add the

spare parts to the scope of license renewal. The applicant credited 10 CFR Part 50,

Appendix B, Criterion XIII for managing the aging of the spare parts. The staff agreed that this

program addresses the immediate and ongoing serviceability of the replacement components

and will adequately manage the aging effects of the spare parts during the period of extended

operation. This inspection issue is closed. -

Operating Experience

The staff reviewed operating experience for the fire protection program. The applicant

identified condition report trending data that discovered discrepancies with fire barrier

components, and resolved the negative trend data and specific conditions by implementing

revised design methods for sealing penetrations.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.1 0.1 adequately manages the

aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.10, of the LRA, the applicant provided the UFSAR supplement for

the fire protection program. The staff reviewed this section and determined that the information

in the UFSAR supplement provides an adequate summary of the program activities. The staff

finds this section of the UFSAR supplement sufficient.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL program

are consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 1 0 CFR 54.21 (d).

3.0.3.2.5.2 Fire Water System

Summary of Technical Information in the Application

The applicant's fire water system is described in LRA Section B.1.10.2, "Fire Water System." In

the LRA, the applicant stated that the program is consistent with, but includes an exception and

enhancement to, GALL AMP XI.M27, "Fire Service Water." This AMP is credited with

performing periodic inspections and functional tests of the fire barriers and a diesel-driven fire

.3-31
pump to ensure that the operability of the fire barriers is maintained and that the fuel supply line

can perform the intended function, respectively.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. Furthermore, the staff reviewed the exception and its

justification, and the enhancement, to determine whether the AMP, with the exception and

enhancement, remains adequate to manage the aging effects for which it is credited.

In Appendix B, Section B.1.10.2, of the LRA, the applicant stated the following exception to

GALL AMP XI.M27:

Element: 3: Parameters Monitored/Inspected

Exception: The applicant does not implement NRC Generic Letter (GL) 89-13, "Service

Water System Problems Affecting Safety-Related Equipment," commitments in

the fire water system program.

The GALL Report identifies the following criterion for the parameters monitored/inspected

program element associated with the exception taken:

GL 89-13 recommends periodic flow testing of infrequently used loops of the fire water

system at the maximum design flow to ensure that the system maintains its intended

function.

The applicant verifies that every fire main segment (excluding individual system supplies) is

clear of obstruction by performing a full-flow test at least once every three years. ISG-04

revised criteria for the GALL AMP XI.M27 parameters monitored/inspected program element to

no longer recommend use of GL 89-13 in determining the system's ability to maintain pressure

and internal system corrosion conditions. Rather, ISG-04 recommends either periodic flow

testing of the fire water system using the guidelines of National Fire Protection Association

(NFPA) 25, Chapter 13, Annexes A and D, at the maximum design flow, or periodic wall

thickness evaluations to ensure that the system maintains its intended function. On the basis of

the applicant's commitment to test fire water system components in accordance with the

applicable NFPA codes and standards, the staff finds that this exception meets the criteria of

ISG-04 and is, therefore, acceptable.

In Appendix B, Section B.1.10.2, of the LRA, the applicant stated the enhancement to GALL

AMP XI.M27:

Elements: 1: Scope of Program

4: Detection of Aging Effects

Enhancement A sample of sprinkler heads will be inspected using the guidance of

NFPA 25, Section 2.3.3.1. The NFPA 25 also contains guidance to

repeat this sampling every 10 years after the initial field service testing.

3-32
The GALL Report identifies the following criterion for the scope of program and detection of

aging effects program elements associated with the enhancement: ; .J .

Sprinkler systems are inspected once every refueling outage to ensure that signs of

degradation, such as corrosion, are detected in a timely manner.

ISG-04 revised criteria for the GALL AMP XL.M27 detection of aging effects program element to

recommend sprinkler head inspections before the end of the 50-year sprinkler head service life'

and at 1 0-year intervals thereafter during the extended period of operation to ensure that signs

of degradation are detected in a timely manner. On the basis of the revised GALL criteria in

ISG-04 and the applicant's'commitment to rely upon applicable codes and standards to develop

test procedures, the staff finds this enhancement to be acceptable.

On the basis of its review of the fire protection and fire water system, the associated"

engineering report, and the operating experience, the staff determined that the fire protection

program is consistent with the GALL Report and that the exceptions and enhancement in the

fire protection program are acceptable.

ODerating Experience

The staff reviewed operating experience for the fire water system program. Trending 'data did

not identify a need for improvement to this program. The applicant has incorporated industry

operating experience regarding the opening of "wet" fire protection systems. Operating

experience shows that opening fire protection systems results in oxygenation of the water,

leading to increased corrosion of the pipe. The applicant revised its quarterly test requirements

for fire protection systems such that they will not open system piping during these tests. The

staff reviewed the results and confirmed that no significant aging of fire protection components

was identified in the review.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.10.2 adequately manages the

aging effects that have been observed at the applicant's plant or at other nuclear plants:

UFSAR Supplement

In Appendix A, Section A.2.1.10, of the LRA, the'applicant provided the UFSAR supplement for

the fire protection program. In Section A.2.1.11 the applicant provides the UFSAR supplement for the fire water system program. The staff reviewed these sections and determined that the

information in the UFSAR supplements provides an adequate summary of the program

activities. The staff finds these sections of the UFSAR supplement sufficient.

* ,; g .,

3-'33
Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL Report

program are consistent with the GALL Report program. In addition, the staff has reviewed the

exceptions and enhancement to the GALL Report program and finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplements for this AMP and finds that they provide an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.6 Reactor Vessel Integrity

Summary of Technical Information in the Application

The applicant credits the Reactor Vessel Integrity AMP with the monitoring of the fracture

toughness properties for the ferritic (low alloy steel) base metal and weld materials in the

ANO-2 RV. The applicant describes the Reactor Vessel Integrity AMP in Section B.1.21 of the

ANO-2 LRA and identifies that the AMP is consistent with the program attributes discussed in

GALL AMP XL.M31, "Reactor Vessel Surveillance," with the following enhancement:

The ANO-2 specimen capsule withdrawal schedule will be revised to withdraw and test a

standby capsule to cover the peak fluence expected through the end of the period of

extended operation.

Staff Evaluation

Criteria for the first 40 years are specified in 10 CFR Part 50, Appendix H (henceforth

Appendix H), "Reactor Vessel Materials Surveillance Program," for monitoring changes in the

fracture toughness of ferritic materials in the reactor beltline region due to neutron irradiation

and the thermal environment. Appendix H requires that the surveillance program design and

withdrawal schedule for the RV surveillance capsules must meet the requirements of American

Society for Testing and Materials (ASTM) E-1 85, "Standard Practice for Conducting

Surveillance Tests for Light Water Cooled Nuclear Power Vessels."

Regulatory Guide (RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials

(May 1988)," describes general procedures acceptable to the NRC staff for calculating the

effects of neutron irradiation embrittlement of the low-alloy steels used for light-water-cooled

RVs. Surveillance data from the Appendix H program are used in RG 1.99, Revision 2

calculations, if applicable. The surveillance data is monitored and trended in accordance with

RG 1.99, Revision 2, and RG 1.190, "Calculational and Dosimetry Methods for Determining

Pressure Vessel Neutron Fluence (March 2001)". The fluence was calculated using the

methodology reported in the Babcock and Wilcox report BAW-2241 P-A, Revision 1, "Fluence

and Uncertainty Methodologies," which was published in April 1999. This methodology has

been approved by the NRC Division of Systems, Safety, and Analysis staff and meets the

uncertainty requirements of RG 1.190.

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The applicant's description of the Reactor Vessel Integrity Program also demonstrates that the

program is designed and implerniented in compliance with the requirements of

10 CFR Part 50, Appendix H, and ASTM E1 85-82, 'Recommended Practice for Surveillance

Tests for Nuclear Reactor Vessels",'and discusses how the implementation of the AMP will be'-

used to provide inputs to the structural integrity assessments required under the requirements

of 10 CFR Part 50, Appendix G for upper shelf energy (USE) assessments and pressuretemperature (P-T) limit assessments, and the requirements of 10 CFR 50.61 for providing the

RV with adequate protection against pressurized thermal shock (PTS) events.' However, the

applicant did not include a revised RV surveillance capsule withdrawal schedule for ANO-2 to

account for the impact of additional neutron fluence exposure that would result from operating

through the period of extended operation. The staff is imposing a license condition on the

Reactor Vessel Integrity Program to ensure that changes to the AMP, as made to

accommodate the extended period of operation, will continue to be reviewed and approved by

the staff. The details of this license condition'are discussed in the staff's evaluation of the

UFSAR Supplement summary description for this AMP, which follows directly after this section.'

With the addition of this license condition, the staff concludes that applicant's Reactor Vessel

Integrity Program is consistent with GALL AMP -XI.M31, and will continue to comply with the

requirements of 10 CFR Part 50, Appendix H,'as amended by the license'condition and is

acceptable.

Operating Experience

The design of the RV Integrity Program was originally reported to the NRC in Combustion

Engineering Topical Report No. A-NLM-005, dated October 30, 1974 and the unirradiated,

baseline test data for the ANO-2 RV base metal and weld materials were reported to the NRC

in Combustion Engineering Topical Report No. TR-MCD-002, dated March 1976. This topical

report indicated that the ANO-2 RV Integrity Program was designed with the RV surveillance

capsules identified as Capsules W83, W97, W104,'W263, W277 and W284. To date, the .

applicant has removed two surveillance capsules, Capsules W97 and W104 from the ANO-2

RV in compliance with its 10 CFR Part 50, Appendix H, program. The applicant reported the,

test results for the plates and welds in the capsules to the NRC in the following topical reports:

* Capsule W97 - data reported in a Batelle Topical Report that was submitted to the NRC

in Arkansas Power and Light Company Letter No. 2CAN028503 (February 8,1985).

* Capsule W1 04 - data report in Babcock and Wilcox Topical Report BAW-2399,-

Analysis of Capsule W-104, Entergy Operations, Inc.,;Arkansas Nuclear One Unit 2

.PowerPlant(September 2001). cE] 3 - -

The applicant's submittal of these topical reports complied with the test data reporting

requirements of Section IV of 10 CFR Part 50,'Appendix H.

Section 4.2 of the ANO-2 LRA demonstrates'that the applicant has appropriately considered the

applicable RV surveillance in the calculations'for the TLAAs on neutron irradiation

1 The data from implementation of the Reactor Vessel Integrity Program provide critical fracture

toughness data inputs for the applicant's time-limited aging analyses (TLAAs) for USE, PTS, and

P-T limits. Refer the staff's evaluations In Section 4.2 of this SER on the related TLAAs on USE,

PTS, and P-T limits for the ANO-2 LRA.

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embrittlement, including the TLAAs for pressurized thermal shock (PTS) calculations, upper

shelf energy (USE) calculations, and pressure-temperature (P-T) limit calculations.

This complies with applicable evaluation criteria in Paragraph §(c))(2) of 10 CFR 50.61 for the

TLAA on PTS and in Paragraph §IV.A. of 10 CFR Part 50, Appendix G, for the TLAAs on USE

and P-T limits. The staff's evaluations of the TLAAs on PTS, USE, and P-T limits are provided

in Section 4.2 of this SER.

On the basis of the review of the above operating experience, the staff concludes that AMP

B.1.21 will adequately manage the aging effects that have been observed at the applicant's

plant or at other nuclear plants.

UFSAR Supplement

The applicant provides the following UFSAR Supplement summary description for the Reactor

Vessel Integrity AMP in Section A.2.1.22 of the ANO-2 LRA:

The Reactor Vessel Integrity Program manages reduction of fracture toughness of

reactor vessel beltline materials to assure that the pressure boundary function of the

reactor vessel is maintained. The program is based on ASTM E-1 85-82, "Standard

Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels," and

includes an evaluation of radiation damage based on pre-irradiation and post irradiation

testing of Charpy V-notch and tensile specimens. Through the Reactor Vessel Integrity

Program, reports are submitted as required by 1 OCFR Part 50 Appendix H.

The applicant's UFSAR Supplement summary description for this AMP provides an acceptable

general description of the Reactor Vessel Integrity AMP and the RV surveillance capsule

withdrawal schedule for ANO-2 that is implemented as part of the AMP. However, the UFSAR

Supplement summary description for this AMP does not include the specific surveillance

capsule withdrawal schedule for the period of extended operation. The applicant has three

standby capsules (capsules 4, 5, and 6) which can be repositioned to address the applicant's

program enhancement. In RAI B.1.21-1, the staff requested that the applicant submit a specific

RV surveillance capsule withdrawal schedule through the end of the period of extended

operation for staff review and approval. In addition, the staff requested that the applicant revise

the UFSAR Table 5.2-12 accordingly.

In response to RAI B.1.21-1, the applicant stated that Capsule 3 is scheduled to be removed at

30 effective full power years (EFPY). The applicant estimated that this capsule will receive

approximately 4.9E1 9 n/cm2 (E 2 1.0 MeV) at 30 EFPY, which is slightly less than the expected

48 EFPY fluence of 5.OE1 9 n/cm2 (E 2 1.0 MeV) discussed in the ANO-2 LRA, Section 4.2.2.

As discussed in Section B.1.21 of the ANO-2 LRA, the ANO-2 specimen capsule withdrawal

schedule will be revised to withdraw and test a standby capsule to cover the peak fluence

expected through the end of the period of extended operation. As specified in Note (a) to

Table 5.2-12 in the ANO-2 LRA, if required, Capsules 4, 5, or 6 will be repositioned to address

the applicant's program enhancement. Alternatively, Entergy may decide to delay the

withdrawal of Capsule 3 to cover the period of extended operation and would, at that time,

notify the NRC of the change to the withdrawal schedule as required by 10 CFR 50,

Appendix H.

3-36
10 CFR Part 50, Appendix H, requires licensees to submit any proposed changes to their

withdrawal schedules to the NRC for review and approval. As mentioned, Table 5.2-12 of the

ANO-2 LRA contains a statement that says prior to changing removal intervals, NRC approval

is required per 10 CFR 50, Appendix H.

To ensure that this requirement will carry forward after the ANO-2 operating license has been

renewed, the staff will impose the following condition in the renewed license for ANO-2 that'

requires Entergy to submit any further changes to the surveillance capsule withdrawal schedule

for NRC review and approval:

All capsules in the reactor vessel that are removed and tested must meet the test

procedures and reporting requirements of ASTM E 185-82 to the extent practicable for

the configuration of the specimens in the capsule. Any changes to the capsule

withdrawal schedule, including spare capsules, must be approved by the NRC prior to

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

Any changes to storage requirements must be approved by the NRC.

With the addition of the license condition, the staff finds that the applicant's response to RAI

B.1.21-1 and the Reactor Vessel Integrity Program are acceptable, and considers this issue

closed.

Conclusion !

The staff has reviewed the Reactor Vessel Integrity Program, as discussed in Section B.1.21 of

the ANO-2 LRA. On the basis of its review of the applicant's program and with the addition of

the license condition discussed above, the staff finds that those portions of the AMP for which

the applicant claims consistency with the GALL program are consistent with the GALL program.

In addition, the staff has reviewed the enhancements to the GALL program and finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).: --

The staff also reviewed the UFSAR Supplement summary description for this AMP, as

described in Section A.2.1.22 of the ANO-2 LRA, and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d). -

3.0.3.2.7 Service Water Integrity

Summary of Technical Information in the Application

The applicant's service water integrity program is described in LRA Section B.1.24, uService

Water Integrity." In the LRA, the applicant stated that the program will be consistent with, but

include exceptions and an enhancement to, GALL program XI.M20, -Open-Cycle Cooling

Water System." This AMP is credited with relying on surveillance and control techniques,

based on the recommendations of NRC Generic Letter 89-13, to ensure that the effects of

aging on the service water system will be managed for the period of extended operation.

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Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report.. Furthermore, the staff reviewed the exceptions and their

justifications, and the enhancement, to determine whether the AMP, with the exceptions and

enhancement, remains adequate to manage the aging effects for which it is credited.

In Appendix B, Section B.1.24, of the LRA, the applicant stated the exceptions to GALL AMP

XI.M20:

Element: 2: Preventive Actions

Exception: The SWIP components are lined or coated only as deemed necessary, they are

not all lined or coated.

Element: 5: Monitoring and Trending

Exception: The frequency of inspections and testing is established according to results, the

frequency of these activities is not set to commence annually and during

refueling outages.

The applicant stated that the service water integrity program uses lining or coating on

components as deemed necessary, whereas GALL program XI.M20 requires the system

components to be constructed of appropriate materials, and lined or coated for protection of the

underlying metal components against aggressive cooling water environments. The applicant

stated that it has conducted various inspections of components over time and either upgraded

the material of the component such that no coating is required, or coated the components

requiring lining or coating. The staff reviewed the service water integrity program and finds that

this exception is acceptable.

The applicant stated that the service water integrity program varies the frequency of inspections

and testing frequency according to results, whereas GALL program XI.M20 requires annual

testing and testing during refueling outages. The staff finds that the difference in inspection

and testing frequency is insignificant since aging effects typically manifest over several years.

The inspection frequencies are determined based on engineering evaluation of inspection

results and in accordance with the applicant's commitments under GL 89-13. The staff finds

this exception to be acceptable.

In Appendix B, Section B.1.24, of the LRA, the applicant stated the enhancement to GALL AMP

XI.M20:

Element: 4: Detection of Aging Effects

Enhancement: The program will check for evidence of selective leaching during visual

inspections.

The GALL Report identifies the following criterion for the detection of aging effects program

element associated with the enhancement:

Inspections for biofouling, damaged coatings, and degraded material condition are

conducted.

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During the audit, the staff asked the applicant to provide the technical justification for

performing visual inspections without hardness testing to detect selective leaching. In its

response, the applicant stated that details on the enhancements to programs to manage loss of

material due to selective leaching are provided in clarification letter 2CAN01 0401, dated ' '

January 22, 2004. The applicant committed to providing these details prior to the period of

extended operation. The staff finds this acceptable..

On the basis of its review of this AMP,-the associated engineering report, and the operating

experience, the staff determined that this'AMP is consistent with the GALL Report and that the'

exceptions and enhancement in the service water integrity program are acceptable.

Operating Experience

The staff reviewed correspondence and reports dealing with the applicant's response to

GL 89-13 and subsequent activities related to the SW system. This included a sample of

condition reports related to the SW system as well as periodic monitoring and trending data.

During the audit, the staff noted that the LRA indicates that minor through wall piping leaks

have occurred and the service water components are routinely inspected to ensure loss of

material and cracking will not degrade the ability of the'service water system to perform its

intended function. The staff asked the applicant to provide the type of inspection used to' detect

the aging effects of loss of material and cracking and the justification for the inspection method.

In its response, the applicant stated that details'on the enhancements to programs to manage

loss of material due to selective leaching are provided in clarification letter 2CAN01 0401, dated

January 22, 2004.' The applicant committed to'providing these details prior to the period of

extended operation. The staff finds this acceptable. '

On the basis of the its review of the above operating' experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.24 adequately manages the aging

effects that have been observed at the applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.25, of the LRA;- the applicant provided the UFSAR supplement for

the service water integrity program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the'program activities.

The staff finds this section of the UFSAR supplement sufficient. - -

Conclusion.

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL Report

program are consistent with the GALL Report program. In addition,.the staff has reviewed the

exceptions and enhancement to the GALL Report program and finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the.CLB for the period of extended operation,-as

required by 10 CFR 54.21 (a)(3).

3-'39
-

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.8 Closed Cooling Water Chemistry Control Program

Summary of Technical Information in the Application

The applicant's closed cooling water chemistry control program is described in LRA Section

B.1.30.2, "Closed Cooling Water Chemistry Control." In the LRA, the applicant stated that the

program is consistent with, but includes exceptions to, GALL program XI.M21, "Closed-cycle

Cooling Water System". This AMP is credited with monitoring and inspecting chemistry

parameters as preventive measures to manage loss of material, cracking, and fouling for closed

cooling water system components.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. Details of the staff's evaluation of the audit and review are documented in the

ANO-2 Audit and Review Report. Furthermore, the staff reviewed the exceptions and their

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

The applicant states that it's closed cooling water chemistry control program includes

preventive measures that manage loss of material, cracking, and fouling for component cooling

water system components. These chemistry activities provide for monitoring and controlling

component cooling water chemistry using ANO-2 procedures and processes based on EPRI

TR-1 07396, "Closed Cooling Water Chemistry Guidelines."

In Appendix B, Section B.1.30.2, of the LRA, the applicant stated the exceptions GALL AMP

Xl.M21:

Element: 3: Parameters Monitored/Inspected

5: Monitoring and Trending

6: Acceptance Criteria

Exception: The program only monitors chemistry parameters.

Element: 4: Detection of Aging Effects

Exception: The program is a preventive program that claims no credit for the detection of

aging effects through performance and functional testing.

Element: 6: Acceptance Criteria

Exception: The nitrite corrosion inhibitor concentrations are maintained within specified

limits, which allow for larger variance (1200 parts per million, or ppm - 4000 ppm)

than recommended (500 ppm - 1000 ppm) in EPRI TR-107396.

The GALL Report identifies the following criteria for program elements: (1) parameters

monitored/inspected, (2) monitoring and trending, and (3) acceptance criteria:

3-40

I
(1) The AMP monitors the effects of corrosion by surveillance testing and inspection in

accordance with standards in EPRI TR-1 07396 to evaluate system and component

performance. For pumps, the parameters monitored include flow and discharge and

suction pressures. For heat exchangers, the parameters monitored include flow, inlet

and outlet temperatures, and differential pressure.

(2) Performance and functional tests are performed at least every 18 months to

demonstrate system operability, and tests to evaluate heat removal capability of the

system and degradation of system components are performed every five years.

(3) System and component performance test results are evaluated in accordance with the

guidelines of EPRI TR-1 07396. Acceptance criteria and tolerances are also based on

system design parameters and functions.

The staff determined that EPRI TR-1 07396 does not recommend equipment performance and

functional testing for monitoring the effectiveness of a water chemistry control program.

Monitoring pump performance parameters is of little value in managing the effects of aging on

long-lived, passive closed cooling water system components. EPRI TR-107396, Section 5.7,

stated that performance monitoring is typically part of an engineering program,which would not

be part of water chemistry. The report further stated that performance monitoring '...can be

used to confirm that conditions in the closed cooling water system are not degrading heat

exchanger performance...."

The staff finds that this EPRI guidance neither requires nor negates performance monitoring.

The staff reviewed the applicant's procedure on chemistry inspections of plant systems and

heat exchangers, and finds that implementation of this procedure enables the applicant to,

continue to confirm the effectiveness of the closed cooling water chemistry control program via

plant inspections. The staff finds this exception to be acceptable. - :.. . : .: - -'- .

The GALL Report identifies the following criterion for the detection of aging effects program

element associated with the exception taken:

The extent and schedule of inspections and testing, in accordance with EPRI

TR-1 07396, assure detection of corrosion before the loss of intended function of the

component. Performance and functional testing, in accordance with EPRI TR-107396,

-ensures acceptable functioning of the closed cooling water system or components

serviced by the closed cooling water system.

The staff reviewed the applicant's implementation procedure which enables the applicant to

confirm the effectiveness of the closed cooling water chemistry control program. Inspections

are performed when systems are opened for-maintenance, when an adverse trend exists, or

when desired by the chemistry department. Thecomponent cooling water heat exchangers are

inspected to assess the effectiveness of chemistrycontrol every time the heat exchangers are

put in wet lay-up. In the past three years, component cooling water heat exchangers have been

inspected more than eight times. -These inspections have been performed for many years.

The staff finds that aging effects on passive mechanical components in the closed cooling

water system are adequately managed without reliance on performance and functional testing.

Therefore, the staff finds this exception to be acceptable. - ;

3-41
The GALL Report identifies the following criterion for the "acceptance criteria" program element

associated with the exception taken:

Corrosion inhibitor concentrations are maintained within the limits specified in the EPRI

water chemistry guidelines for closed cooling water systems.

The staff noted that the applicant is currently drafting changes to a procedure to incorporate the

EPRI guidelines on nitrite corrosion inhibitor. The procedure will specify that nitrite inhibitor

concentrations are to be maintained in accordance with EPRI TR-107396.

By letter dated May 19, 2004, the applicant stated, in response to question B.1.30.2-5, that it

had revised its procedure to incorporate the EPRI guidelines on nitrite corrosion inhibitor.

Therefore, this is no longer an exception to the GALL program.

On the basis of the applicant's response, the staff finds this exception to no longer apply. The

staff confirms that the acceptance criteria program element is consistent with the GALL Report

with respect to nitrite corrosion inhibitor concentrations, and therefore, finds this to be

acceptable.

On the basis of its review of this AMP, the associated engineering report, and the operating

experience, the staff determined that this AMP is consistent with the GALL Report and that the

exceptions in the closed cooling water chemistry control program are acceptable.

Operating Experience

The operating experience review, performed by the applicant, did not identify any condition

reports or licensee event reports relating to chemical excursions in the systems covered under

the closed cooling water chemistry control program . Also, the condition report trending data

did not identify recurrent component degradation in the systems covered under this AMP. The

review of condition reports, condition report trending data, and interviews with the plant

technical staff confirmed the program requirements are effectively implemented.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that AMP B.1.30.2 adequately manages the

aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.32, of the LRA, the applicant provided the UFSAR supplement for

the water chemistry control - closed cooling water chemistry control program, which states that

the closed cooling water chemistry control program includes preventive measures that manage

loss of material, cracking, and fouling, as applicable, for component cooling water system

components. These chemistry activities provide for monitoring and controlling component

cooling water chemistry using procedures and processes based on EPRI TR-1 07396, "Closed

Cooling Water Chemistry Guidelines."

During the audit, the staff noted that for the closed cycle cooling water system described in the

SRP-LR, Table 3.3-2, it is stated that '...The program relies on preventive measures to

3-42
minimize corrosion by maintaining inhibitors and by performing non-chemistry monitoring

consisting of inspection and nondestructive evaluations based on the guidelines of

EPRI-TR-107396 for closed-cycle cooling water systems." During the audit, in question

B.1.30.2-7, the staff noted that the applicant neither referred to the inspections performed nor

specified the exceptions to GALL AMP Xl.M21, "Closed-Cycle Cooling Water System' in LRA

Appendix A, Section A.2.1.32. The staff requested that the applicant revise the LRA

Appendix A, Section A.2.1.32 to be consistent with the GALL Report, Table 3.3-2, or justify its

acceptability (RAI B.1.30.2-1).

In its response dated May 19, 2004, the applicant stated LRA Section B.1.30.2 provides

justification for the exceptions between the closed cooling water chemistry control program and

GALL-AMP XI.M21, including the exception for inspection and nondestructive evaluations;

therefore additional information is not required. The applicant stated that the UFSAR

Supplement, LRA, Appendix A, Section A:2.1.32 contains a summary description of the

program as required by 10 CFR 50.54.21(d).-,- -

The staff reviewed the applicant's response and the UFSAR supplement and confirms that it

provides an adequate summary description of the program, as identified in the SRP-LR UFSAR

supplement table and as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

elements of the program for which the applicant claimed consistency with the GALL Report

program are consistent with the GALL Report program. In addition, the staff has reviewed the

exceptions to the GALL Report program and finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds 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 Plant-Specific

In Appendix B of the LRA, the applicant indicated that the following AMPs were plant-specific:

* Alloy 600 Aging Management Program (B.1 .1)

* Bolting and Torquing Activities Program (B.1.2)

* Heat Exchanger Monitoring Program (B.1.12)

* Inservice Inspection - Containment Inservice Inspection (CII) Program (B.1.13)

* Inservice Inspection - Inservice Inspection (ISI) Program (B.1.14)

* Oil Analysis Program (B.1.17) .-

* Periodic Surveillance and Preventive Maintenance Program (B.1.18)

Pressurizer Examinations Program (B.1.19)

System Walkdown Program (B.1.28) '

* Wall Thinning Program (B.1.29) - * Water Chemistry Control - Auxiliary Systems Water Chemistry Control Program

(B.1.30.1)

23-43
For AMPs that are not consistent with or not addressed by the GALL Report, the staff

performed a complete review of the AMPs to determine if they were 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 Alloy 600 Aging Management Program

Summary of Technical Information in the Application

The applicant credits the Alloy 600 Aging Management Program with the management of the

cracking due to primary water stress-corrosion cracking (PWSCC) in Alloy 600 and Alloy 690

components and Alloy 52/152 and Alloy 82/182 welds not covered by the applicant's Reactor

Vessel Head Penetration Program or by the Steam Generator Integrity Program. The applicant

discusses this program in Section B.1.1 of the ANO-2 LRA. The applicant's Reactor Vessel

Head Penetration Program, AMP B.1.20, is credited with the management of cracking of the

Alloy 600 RV head penetrations and the Steam Generator Integrity Program, AMP B.1.25, is

credited with the management of cracking of the Alloy 690 steam generator tubes and plugs for

the period of extended operation.

The applicant indicated that the Alloy 600 Aging Management Program is a plant-specific

program for the ANO-2 LRA and discussed the AMP in terms of the 10 program elements

recommended in NUREG-1 800, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants" (SRP-LR) and the ability of this program to manage the

applicable effects of aging. The applicant also included an applicable UFSAR Supplement

summary description for the Alloy 600 Aging Management Program in Section A.2.1.1 of the

ANO-2 LRA.

Staff Evaluation

The staff assessed the corrective actions, confirmation process, and administrative controls

program attributes of the Alloy 600 Aging Management Program as part of the staff's

assessment of the applicant's Quality Assurance Program, which is evaluated in Section 3.0.4

of this SER. The staff evaluation of the remaining program attributes for the ANO-2 Alloy 600

Management Program is given in the following evaluations.

[Program Scope] The scope of the Alloy 600 AMP includes the RCS piping, the pressurizer,

the reactor pressure vessel, and the steam generators. The staff concludes that the program

scope program attribute is acceptable because it includes ASME Code Class 1 Nickel-Alloy

base metal and weld components in the scope of the program, including those used in the

fabrication of the ANO-2 reactor vessel, pressurizer, RCS piping, and steam generator

systems.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent aging effects or mitigate aging degradation. In RAI B.1.1-2, the staff noted that several

preventive actions and common industry practices have been used to manage Alloy 600/82/182

PWSCC, and requested that the applicant provide a description of any preventive actions

and/or water chemistry monitoring programs that ANO-2 is currently implementing that may be

used to address the Alloy 600/82/182 cracking issue.

3-44
In response to RAI B.1.1-2, the applicant stated that ANO-2 has taken preventive actions to

address the Alloy 600/82/182 cracking issue, however, these actions are not part of the Alloy

600 Aging Management Program. Various Alloy 600 pressurizer heater sleeves, instrument

nozzles,' and hot leg instrument nozzles have been repaired due to PWSCC.- The repairs -

involve one of two methods, both of which remove Alloy 600 material from a pressure boundary

function. One repair method replaces the Alloy 600 nozzles with Alloy 690 nozzles while the

other utilizes no nickel-based alloy material'in'a''pressure boundary role (i.e., the'repairs involve

installation of mechanical nozzle seal assemblies)., Alloy 690 is an industry standard for

replacement of Alloy-600 components; In'addition, the ANO-2 Water Chemistry Control

Prograni controls contaminants known to contribute to PWSCC. As described in Section

B.1.30.3 of the LRA, the ANO-2 Primary Water Chemistry Control Program is based on EPRI

TR-105714.

The applicant concludes that ANO-2 does take preventive actions to mitigate degradation of

Alloy 600 components and Alloy 82/182 filler welds. 'Actions that are taken are consistent with

industry practice and include maintenance of stringent water chemistry controls in accordance

with industry accepted guidelines and replacement of faulty Alloy 600/82/182 components with

materials significantly less susceptible to PWSCC. The staff finds the response acceptable and

considers this issue closed. .<

[Parameters Monitored or Inspected] The applicant stated that the Alloy 600 Aging

Management Program monitors the effect of PWSCC cracking using the examination and

inspection requirements of the ASME Code, Section Xl. The aging effects monitored by the

Alloy 600 Aging Management Program are'consistent with those evaluated and accepted by the

staff in Sections 3.1.2.1.1, 3.1.2.1.3, and 3.1.2.1.4 of this SER. The aging effect monitored by

the AlloyG600Aging Management Program (i.e.,'cracking) is therefore acceptable to the staff.

[Detection of Aging Effects'and Monitoring and Trending] The applicant stated that the Alloy

600 Aging Management Progra'm will detect cracking by PWSCC prior to loss of component

intended function. Selected Alloy 600, Alloy 52/152 and Alloy 82/182 locations receive

examination in accordance with the requirements of the ASME Code, Section Xl. The applicant

stated that pressure measurement, vent, upper level, and temperature nozzles, heater sheaths,

heater sleeves; and end plugs will receive visual examination (VT-2) from the exterior of the

vessel in accordance with the requirements of the ASME Code, Section Xl, Examination

Category B-P. In RAI B.1.1-3, the staff noted that for many of these components the Alloy 600

pressure boundary welds are covered by insulation.: Service experience has shown that early

indications of through-wall leakage (e.g., boric acid on the component surface) are very difficult

to detect when VT-2 examinations are performed with'the insulation in-place. The staff

requested that the applicant provide justification for not removing insulation when performing

VT-2 examinations on the components mentioned above. The staff also requested that the

applicant provide the frequency of inspection and the results of any volumetric non-destructive

examination that has been performed.'

In response to RAI B.1.1-3, the applicant stated that, as described in Section B13.1.4 on page

B-12 of the'LRA, the ANO-2 pressurizer heater and small-bore nozzles are visually inspected in

addition to the ASME Code, Section XI, Examination Category B-P inspections. Insulation is

removed if required to allow for bare metal examination of an area'360 degrees around the

small nozzles and penetrations for evidence'of boric acid residue. The inspections are

'3-45
a

performed each refueling outage. The staff finds the response acceptable and considers this

issue closed.

In the Alloy 600 Aging Management Program under the program attribute, "Detection of Aging

Effects," the applicant states that guidance from the MRP in conjunction with the PWR owners

groups will be used to identify critical locations for inspection and augmentation of existing ISI

inspections at ANO-2 where appropriate. In RAI B.1.1-4, the staff requested that the applicant

identify the date that ANO-2 commits to submit, for review and approval, an augmented aging

management program that includes all recommendations from the industry's strategic plan, and

meets the 10 elements in accordance with the guidance in NUREG-1 800, Appendix A.1, "Aging

Management Review - Generic," Table A.1-1, "Elements of an Aging Management Program for

License Renewal." The staff noted that the date must be prior to the period of extended

operation. The staff also noted that this commitment should be documented in the UFSAR.

In response to RAI B.1.1-4, the applicant stated that PWSCC of nickel-based alloys is a current

license term issue. The applicant stated that issues that are relevant to current plant operation

will be addressed by the existing regulatory process within the present license term rather than

deferred until the time of license renewal. With regard to updating the UFSAR, the applicant

stated that a commitment will be added to the UFSAR supplement. During development of the

ANO-2 Alloy 600 Aging Management Program, the applicant stated that guidance developed by

the EPRI MRP for the selection, inspection, and evaluation of nickel-based alloy components

will be considered.

In RAI B.1.1-1, the staff requested that the applicant confirm that all of the components listed in

the Alloy 600 Aging Management Program are covered under the ISI requirements of Section

Xl of the ASME Code. The staff also requested that the applicant identify any components that

are not covered by the ASME Code, Section XI ISI requirements. In addition, the staff

requested that the applicant provide a complete description of the proposed inspections

including a technical justification for the inspection method and frequency for any components

that are identified.

In response to RAI B.1.1-1, dated July 22, 2004 (refer to Entergy Letter No. 2CAN070405), the

applicant stated that all nickel-based alloy items listed in Section B.1.1 of the LRA are included

in the ANO-2 ISl.Program with the exception of the thermal sleeves, the cladding on the

pressurizer lower head, the RV lower shell and head, and the steam generator tubesheet, the

steam generator channel head divider plate and primary nozzle rings, and the pressurizer

heater support plates and heater support plate brackets. The applicant contends that the items

that are inspected as part of the ANO-2 ISI Program have a greater susceptibility to PWSCC

due to physical configuration or operational conditions (e.g., temperature) than those listed

above, and the items listed above that are not volumetrically or visually inspected are bounded

by the items that receive examinations in accordance with the ASME Code, Section Xl. The

applicant acknowledges that the EPRI Materials Reliability Project (MRP) in conjunction with the

PWR owners groups is developing a strategic plan to manage PWSCC of nickel-based alloy

components, and states that guidance developed by the MRP and the owners groups will be

used to identify the need for augmenting existing ISI inspections at ANO-2 where appropriate.

The applicant also provided the following supplemental response to RAI B.1.1-1 in Entergy

Letter No. 2CAN090402, dated September 10, 2004:

3-46
Primary water stress corrosion cracking (PWSCC) of nickel-based alloys is a current

license term issue. As such, interaction between Entergy and the NRC Staff is ongoing

to 'develop a program to manage the effects of aging due to this mechanism. In

accordance with the statements of consideration, issues that are relevant to current

plant operation are addressed by the existing regulatory process within the present

license term rather than deferred until the time of license renewal. Consequently, the

existing regulatory process provides assurance that aging effects caused by PWSCC of

nickel-based alloys will be adequately managed during the period of extended operation.

Consistent with all programs credited for license renewal at ANO-2, the Alloy-600

Program will be available on-site for NRC review. In addition, as requested by the NRC

Staff,- a description of the program will be submitted to the NRC for review and approval.

'The submittal date will be at least 24 months prior to the period of extended operation.

The applicant's descriptions for the Alloy 600 AMP, as discussed in Section B.1.1 of the ANO-2

LRA and in the applicant's responses to RAI BA.1 -1 dated July 22, 2004, and September 10,

2004, clarify two important attributes for the Alloy 600 AMP:

4. The applicant will participate in the EPRI-MRP's studies on PWSCC of ASME Code

Class 1 Nickel-Alloy components and will use the guidance developed by the EPRI-MRP

and the owners groups to identify the need for augmenting existing IS inspections at

ANO-2, where appropriate. ;

5. The applicant has committed to submitting an inspection plan for the ANO-2 ASME

Code Class 1 Nickel-Alloy components to the staff for review and approval at least 24

months prior to entering the period of extended operation for the unit.

The staff has confirmed that the applicant manages PWSCC of the ANO-2 upper reactor vessel

(RV) head penetration nozzles in accordance with a NRC-approved program that complies with

the applicable augmented inspection requirements of NRC Order EA-03-009. This program is

implemented through the applicant's Reactor Vessel Head Penetration Program. The staff has

also confirmed that the applicant plans to.manage.PWSCC of Nickel-Alloy base metal and weld

components in the pressurizer system in accordance with commitments made in the applicant's

response to NRC Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials Used in the

Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at Pressurized

'Water Reactors (May 28, 2004). This response is provided in Entergy Letter No. OCAN070404,

dated July 27, 2004.

For the remaining ASME Code Class 1 Nickel-Alloy components, the EPRI MRP's initiatives on

PWSCC of ASME Code Class 1 Nickel-Alloy components are being performed to assess the

need to implement augmented inspection of the components beyond those currently required

by Section Xl of the ASME Code, as invoked by 10 CFR 50.55a.' The staff concludes that this

is an acceptable process for managing aging in these components, because: (1) Entergy will ,

apply acceptable industry guidelines that will ensure that only those inspections will be used

that are capable of detecting degradation prior to a loss of component intended function,- (2) it

will allow the staff to review the applicant's inspection plans for these components as based on

the industry recommendations, and (3) it will provide the staff an opportunity to resolve with the

applicant any issues that may potentially arise with the inspection plan. ,

'3-47
Records of the inspection program, examination and test procedures, examination/test data,

and corrective actions taken are maintained in accordance with the requirements of ASME

Section Xl, Subsection IWA. The staff finds this approach acceptable since the ASME Code

requires that the applicant maintain inspection records, and the corresponding corrective

actions.

Based on the applicant's commitments for performing augmented inspections of the Alloy

82/182/600 materials used in the fabrication of the ANO-2 upper RV head penetration nozzles

and pressurizer penetration nozzles and steam space piping components, and the applicant's

commitment to submit an inspection plan for NRC review and approval 24 months prior to the

entering the period of extended operation for the remaining Nickel-Alloy components, the staff

concludes that the Detection of Aging Effects and Monitoring and Trending program attributes

are acceptable. To obtain NRC staff approval of its proposed inspection plan regarding Nickel -

Alloy components prior to entering the period of extended operation for ANO-2, the applicant

must submit a license amendment request. After the NRC staff's approval of the inspection

plan, any future changes to the inspection plan will be evaluated in accordance with 10 CFR

50.59.

[Monitoring and Trending] Records of the inspection program, examination and test

procedures, examination/test data, and corrective actions taken are maintained in accordance

with the requirements of ASME Section Xl, Subsection IWA. The staff finds this approach

acceptable since the ASME Code requires that the applicant maintain inspection records, and

the corresponding corrective actions.

[Acceptance Criteria] The applicant stated that the acceptance standards specified in IWB3500 will be applied to component locations that receive ASME Section Xl volumetric, surface,

and visual examinations. The applicant also stated that the acceptance criteria for visual

inspections require that cognizant members of the system engineering, quality control and

design engineering departments review the inspection results for indications of leakage. If

abnormalities are identified, a condition report is issued. All through-wall pressure boundary

leakage must be corrected prior to plant start-up. The staff notes that for the ASME Code

Class 1 Alloy 600 components within the scope of the applicant's Alloy 600 Aging Management

Program, the results of these industry initiatives may include recommendations for

implementing more stringent alternative acceptance criteria to those currently required by

Section Xl of the ASME Code. These actions are consistent with current industry practices and

the staff finds this to be acceptable.

[Operating Experience] The applicant stated that the Alloy 600 Aging Management Program is

a new program for which there is no specific operating experience for ANO-2. The staff is

aware of several reported cases of degradation in Alloy 600 weld components of other U.S.

PWRs, including several reported cases of degradation in other Combustion Engineering (CE)

Nuclear Steam Supply Systems (NSSS) design units. Specifically, PWSCC has been reported

in Alloy 82/182 J-groove welds that are used to join Alloy 600 small bore nozzles to

CE-designed pressurizers, steam generators, and/or hot legs. In RAI B.1.1-5, the staff noted

that it is important for the applicant to review relevant industry service experience and

incorporate lessons learned into the Alloy 600 program. Therefore, the staff requested that the

applicant discuss what industry initiatives it plans to follow in order to incorporate experience

related to Alloy 600 into the ANO-2 Alloy 600 AMP.

3-48
In response to RAI B.1.1-5, the applicant'stated that, as defined in the Standard Review Plan

(NUREG-1 800), the Operating Experience program element describes the operating

experience of the aging management program, including past corrective actions resulting in

program enhancements or additional programs.- Therefore, the applicant concluded that, as a

new program,'the ANO-2 Alloy 600 Aging Management Program has no relevant operating

experience as defined in NUREG-1 800. The applicant repeated its. statement that guidance

developed by the EPRI MRP and the PWR owners groups will be used to identify critical

locations for inspection and augmentation of existing ISI inspections at ANO-2 where

appropriate.

However, there is current generic operating experience that is applicable to the detection of

PWSCC in the Alloy 82/182/600 components of the ANO-2 RCPB. These operating experience

events that are discussed in NRC Order EA-03-009, and in NRC Bulletin 2004-01. The -

applicant is using its commitments made in response to the augmented inspection

requirements'of NRC Order EA-03-009 and Revision 1 of the Order and the Reactor Vessel

Head Penetrations Program as the basis for managing PWSCC in the ANO-2 upper RV head

penetration nozzles. These commitments are discussed and evaluated in Section B.1.20, - -

Reactor Vessel Head Penetration, of this SER., The applicant is using its commitments that

were made' in response to NRC Bulletin 2004-01 'as the basis for managing PWSCC in the

ANO-2 pressurizer penetration nozzles. These commitments are identified in Entergy Letter

No.' OCAN070404, Response to NRC 2004-01 Regarding Inspection of Alloy 82/182/600

Materials Used in Pressurzer Penetrations and Steam Space Piping Components (July 27,

2004), and include a commitment to perform bare-metal visual examinations of the Nickel-Alloy

components'in pressurizer penetrations during subsequent refueling outages, starting with

refueling outage No. 17 in Spring 2005. -

The staff concludes that the Operating Experience program attribute for the Alloy 600 Aging:

Management Program is acceptable because the applicant has addressed the safety

implications of the generic operating experience and has used the experience to augment the

inspection program for the upper RV head penetration nozzles, as required by NRC Order EA03-009 and for Nickel-Alloy pressurizer penetration components, as recommended in NRC

Bulleting 2004-01.

UFSAR Supplement

The applicant provides the following Updated Final Safety Analysis Report summary description

for the Alloy 600 Aging Management Program in Section A.2.1.1. of the ANO-2 LRA:

This program will manage aging effects of alloy 600/690 items and alloy 52/152 and

82/182 welds in the reactor coolant system that are not addressed by the Reactor

Vessel Head Penetration Inspection Program, Section A.2.1.21, and the Steam

Generator Integrity Program, Section A.2.1.26. This program will detect cracking from

primary water stress corrosion cracking (PWSCC) by using the examination and

inspection requirements specified in ASME Section Xl. The Alloy 600 Aging

Management Program will be initiated prior to the period of extended operation.

-The applicant also provided the following revised FSAR Supplement summary description for

the Alloy 600 Aging Management Program in Entergy Letter No. 2CAN090403, dated

September 23, 2004: -

- 3-49
A.2.1 .1 Alloy 600 Aging Management Program

This program will manage aging effects of alloy 600/690 items and alloy 52/152 and

82/182 welds in the reactor coolant system that are not addressed by the Reactor

Vessel Head Penetration Inspection Program, Section A.2.1.21, and the Steam

Generator Integrity Program, Section A.2.1.26. This program will detect cracking from

primary water stress corrosion cracking (PWSCC) by using the examination and

inspection requirements specified of ASME Section Xl, as augmented by commitments

made in response to NRC correspondence. The Alloy 600 Aging Management Program

will be initiated prior to the period of extended operation.

For the CLB for ANO-2, the applicant has proposed some augmentation of the ASME Section

XI ISI requirements for ASME Code Class 1 Nickel-Alloy components. The staff has confirmed

that the applicant has committed to implementing the augmented inspection requirements of

NRC Order EA-03-009 and Revision 1 of the Order for inspections of the upper RV head and its

penetration nozzles. 'For the period of extended operation, the applicant will implement these

requirements and manage PWSCC in the ANO-2 upper RV head penetration nozzles through

implementation of the Reactor Vessel Head Penetrations Program. These requirements and

commitments are discussed and evaluated in Section B.1.20, Reactor Vessel Head

Penetration, of this SER. The staff has also confirmed that the applicant is using its

commitments that were made in response to NRC Bulletin 2004-01 as the basis for managing

PWSCC in the ANO-2 pressurizer penetration nozzles. These commitments are identified in

Entergy Letter No. OCAN070404, Response to NRC 2004-01 Regarding Inspection of Alloy

82/182/600 Materials Used in Pressurizer Penetrations and Steam Space Piping Components

(July 27, 2004), and include a commitment to perform bare-metal visual examinations of the

Nickel-Alloy components in pressurizer penetrations during subsequent refueling outages,

starting with refueling outage No. 17 in Spring 2005. These commitments comply with

augmented inspection requirements of NRC Order. EA-03-009 and conform to the staff's

recommendations for augmented examinations of pressurizer penetration nozzles and steam

space piping components, as recommended in NRC Bulletin 2004-01.

The staff has also confirmed that the applicant has committed to submit the inspection plan for

the Alloy 600 Aging Management Program to the staff for review and approval at least 24

months prior to entering the period of extended operation for ANO-2 and has incorporated this

commitment into the Commitment Tracking List for the ANO-2 LRA, as specified in Entergy

Letter No. Letter No. 2CAN090402, dated September 10, 2004. Based on the FSAR

Supplement Summary description for the Alloy 600 Aging Management Program and the

applicant's commitments for augmented inspections of the upper RV head penetration nozzles

and pressurizer penetration nozzles and for submittal of the inspection plan for the AMP, the

staff concludes that the revised FSAR Supplement summary description for the Alloy 600 Aging

Management Program is acceptable.

Conclusion

The staff has reviewed the Alloy 600 Aging Management Program, as discussed in Section

B.1.1 of the ANO-2 LRA. On the basis of its review of the applicant's program including the

applicant's commitment to request NRC staff review and approval of the Nickel-Alloy inspection

program, the staff finds that the program adequately addresses the 10 program elements

defined in Branch Technical Position (BTS) RLSB-1 in Appendix A.1 of the SRP-LR, and that

3-50

I
the program will adequately manage the aging effects for which it is credited so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR Supplement summary description for this AMP, as

described in Section A.2.1.1 of the ANO-2 LRA, and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.3.2 Bolting and Torquing Activities Program

Summary of Technical Information in the Application

The applicant described its Bolting and Torquing Activities Program in Section B.1.2 of

Appendix B to the Application. It is a plant-specific program in ANO-2. The applicant stated

that this program relies on recommendations for a comprehensive bolting integrity program, as

delineated in the Electric Power Research Institute EPRI NP-5067, "Good Bolting Practices." -

This program also relies on industry recommendations for comprehensive bolting maintenance,

as delineated in EPRI TR-104213, "Bolted Joint Maintenance & Applications Guide," for

pressure retaining bolting. The applicant stated that a similar program based on EPRI NP-5067

and EPRI TR-1 04213 has previously been evaluated and approved by the NRC as documented

in NUREG-1743, "Safety Evaluation Report Related to the License Renewal of Arkansas

Nuclear One, Unit 1."

Staff Evaluation

The staff evaluation of the ANO-2 Bolting and Torquing Activities Program focused on how the

program manages the aging effect through effective incorporation of the following ten

attributes: program scope, preventive or-mitigative actions, parameters monitored/inspected,

detection of aging effects, monitoring and trending, acceptance criteria, corrective actions,

confirmation process, administrative controls, and operating experience.

[Program Scope] The applicant stated that the program covers bolting in high temperature

systems and in applications subject to significant vibration as determined during aging

management review. ' - ;

In RAI B.1.2-1, the staff requested that the applicant clarify whether the program covers all

bolting within the scope of license renewal, greater than or smaller than 2-inch diameter,

including safety-related bolting, bolting for.NSSS component supports, bolting for other

pressure retaining components, and structural bolting. The staff requested that the applicant

provide assurance that the recommendations and guidelines for the plant-specific bolting

program conform to industry's technical guidelines.: By letter dated April 6, 2004, the applicant

stated that the Bolting and Torquing Activities Program applies to closure bolting for

components subject to aging management review in high temperature systems and in

applications subject to significant vibration. Thus, it applies to safety-related bolting, nonsafetyrelated bolting, and bolting for pressure retaining components. It does not apply, however, to

bolting for NSSS components supports and structural bolting. The programs managing aging

effects of component supports and structural bolting are listed in the tables in LRA Section 3.5,

Structures and Component Supports. In addition, the applicant stated that the program covers

both larger than and smaller than or equal to 2-inch diameter bolting.

3-51
The applicant reiterated the statement in GALL XI.M1 8, Bolting Integrity, "The industry's

technical basis for the program for safety-related bolting and guidelines for material selection

and testing, bolting preload control, inservice inspection (ISI), plant operation and maintenance,

and evaluation of structural integrity of bolted joints, are outlined in EPRI NP-5769, with the

exceptions noted in NUREG 1339. For other bolting, this information is set forth in EPRI

TR-104213." Also, EPRI NP-5769 states that EPRI NP-5067, Good Bolting Practices, satisfies

the industry's need for guidance on assembly of bolted joints. In ANO-2 LRA, EPRI NP-5067

and EPRI TR-104213, Bolted Joint Maintenance & Application Guide are utilized as guidance in

the Bolting and Torquing Activities Program. Based on the above, the staff considered that the

guidelines utilized for the Bolting and Torquing Activities Program reflect industry practice. RAI

B.1.2-1 is, therefore, closed.

[Preventive Actions] The applicant stated that preventive actions include proper selection of

bolting material and the use of the appropriate lubricants and sealants in accordance with the

guidelines of EPRI NP-5067. Initial inspection of bolting for pressure retaining components

includes a check of the bolt torque and uniformity of the gasket compression after assembly.

Hot torque checks are not applied to all bolted closures within the scope of this program, but

are procedurally controlled if vendor-recommended or if determined necessary on a case-bycase basis. The staff considered the preventive actions taken by the applicant to be adequate

in preventing the aging effect of loss of mechanical closure integrity, due to loss of preload or

vibration, and are, therefore, acceptable.

[Parameters Monitored/Inspected] The applicant stated that torque values are monitored when

the bolted closure is assembled. Maintenance personnel visually inspect components used in

the bolted closures to assess their general condition during maintenance. .1

In RAI B.1.2-2, the staff requested the applicant to discuss the specifics of the conditions of the

closure bolting to be inspected, and to explain why torque values are the only parameters to be

monitored. The staff also requested the applicant to provide details of the methods of its visual

inspection, and explain why inspection techniques other than visual inspection are not included

in the program. By letter dated April 6, 2004, the applicant stated that under the Bolting and

Torquing Activities Program, loss of mechanical closure integrity is managed by proper torquing

during assembly of the bolted closure. The program is a preventive program rather than an

inspection program to detect the effects of aging. Visual inspections to manage the effects of

aging are not included in this program. Instead, as described in LRA Section B.1.2 under

Parameters Monitored/Inspected, maintenance personnel visually inspect components used in

the bolted closures to assess their general condition during maintenance. Prior to assembly,

the mating surfaces and bolting components are inspected for manufacturing defects, galls,

spurs, or dirt. After assembly, the closure is inspected for uniformity of gasket compression,

proper thread engagement and proper locking tab installation. The applicant stated that torque

values are the only parameters specified to be monitored because the aging effect being

managed is loss of mechanical closure integrity due to loss of pre-load, not loss of material. If

loss of material is an aging effect requiring management for the same bolted closures, it is

managed by another program such as System Walkdown or Boric Acid Corrosion Prevention

Program. The staff considered the applicant's response to be adequate in explaining how the

mating surfaces and bolting components are inspected prior to and after assembly, and why

torque values are the only parameters to be monitored. RAI B.1.2-2 is, therefore, closed

3-52
[Detection of Aging Effects] As stated earlier,'the program is a preventive program, not an

inspection program for detecting the effects of aging. Preventive actions under the program

prevent loss of mechanical closure integrity.

There was no discussion in LRA as to what aging effects/mechanisms requiring management

are included under the aging effect of loss of mechanical closure integrity. In RAI B.1.2-3, the

staff requested that the applicant provide a detailed description of the aging effects which : l

attribute to loss of mechanical closure integrity, and to discuss how the aging management

program is expected to manage them. The staff also requested that the applicant ensure that,

as delineated in GALL XI.M1 8, Bolting Integrity, the inspection requirements of the ASME

Code, Section Xi, are met. By letter dated April 6, 2004, the applicant stated that loss of

mechanical closure integrity is the aging effect caused by loss of preload due to high

temperature or vibration. If loss of material is an aging effect requiring management for the

same bolted closures, it is managed by another program such as System Walkdown or Boric

Acid Corrosion Prevention Program. The GALL program XI.M1 8, "Bolting Integrity," stipulates

the inservice inspection requirements of the-ASME Code, Section Xl. These IS requirements

are included in the ANO-2 Inservice Inspection Program for Class 1, 2, and 3 bolted closures.

However, these inspection requirements are focused on identifying the aging effect of cracking.

Since cracking is not an aging effect requiring management for Non-Class 1 bolted closures,

the applicant stated that the Inservice Inspection Program was not credited as an aging

management program for the ASME Class 2 and 3 bolted closures. The applicant also stated

that inspection requirements of ASME Code, Section Xi, will continue to be met as required by

1 OCFR50.55a during the period of extended operation. The staff considered the applicant's

response to be adequate in explaining the difference between the Bolting and Torquing

Activities Program and the GALL XI.M1 8, Bolting Integrity, and in ensuring that inspection

requirements of ASME Code, Section Xl, will continue to be met. RAI B.1.2-3 is, therefore,

closed. -

[Monitoring and Trending] The applicant stated that torque values are monitored during the bolt

torquing process. Trending is not applicable to this program. The ANO-2 Corrective Action

Program applies. This provides assurance that trends entailing repeat failures to meet

acceptance criteria will be identified and addressed with appropriate corrective actions.

In RAI B.1.2-4, the staff requested the applicant to discuss the details of the inspection

schedule and its basis. By letter dated April 6,'2004, the applicant stated that under the Bolting

and Torquing Activities Program, loss of mechanical closure integrity is managed by proper

torquing during assembly of the bolted closure. -The applicant stated that visual inspections to

find evidence of aging effects are not performed under-this program, thus there is no frequency

to be provided. The staff considered the applicant's response to be adequate in explaining why

there is no inspection frequency involved in the Bolting and Torquing Activities Program, as

versus to the Inservice Inspection Program included in GALL XI.M1 8, Bolting Integrity. RAI

B.1.2-4 is, therefore, closed.

[Acceptance Criteria] The applicant stated that acceptance criteria are provided in site

procedures. Typical criteria are that mating surfaces are smooth and free of major defects.;

Other criteria include proper and adequate thread engagement and use of appropriate torque

values.

3-53
To ensure that mating surfaces perform their intended function as a pressure retaining

boundary, the staff requested in RAI B.1.2-5 that the applicant enhance the criteria by requiring

that the surfaces be thoroughly inspected, for potential aging effects, such as corrosion,

cracking, and/or leaking. This includes identification of all relevant indications and signs of

degradation at the surfaces. By letter dated April 6, 2004, the applicant stated that under the

Bolting and Torquing Activities Program, loss of mechanical closure integrity is managed by

proper torquing during assembly of the bolted closure. As discussed in its response to RAI

B.1.2-2, the applicant stated that the inspection of mating surfaces under this program is an

inspection for manufacturing defects, galls, spurs, or dirt prior to assembly of the bolted closure.

Management of aging of component mating surfaces to ensure that they perform their intended

function as a pressure retaining boundary is performed by the program which manages aging of

the component itself. The staff considered the applicant's response to be adequate in defining

the acceptance criteria of the program, which is the smoothness of the mating surfaces and the

proper torque values. RAI B.1.2-5 is, therefore, closed.

[Operating Experience] The applicant stated that the ANO-2 Bolting and Torquing Activities

Program is the same program credited for ANO-1 license renewal. ANO bolting and torquing

practices were evaluated during NRC review of the ANO-1 LRA. On the basis of the review,

the NRC staff found that the Bolting and Torquing Activities Program, which is part of the CLB,

will continue to be adequate to assure that threaded joints will perform their intended functions

during the period of extended operation.

The applicant stated that repetitive occurrences of deficient bolting and torquing activities are

identified by the ANO staff. Corrective actions are established to address deficient conditions

regarding torquing of mechanical fasteners and to preclude their recurrence. The applicant

stated that this operating experience demonstrates that the Bolting and Torquing Activities

Program will provide assurance that the aging effects associated with bolted closures will be

managed such that applicable structures and components will continue to perform their

intended functions consistent with the current licensing basis for the period of extended

operation. In RAI B.1.2-6, the staff requested that the applicant elaborate on the types of

repetitive occurrences of deficient bolting and torquing activities, and how the deficiencies were

dispositioned. By letter dated April 6, 2004, the applicant stated that in 1998 the ANO staff

identified repetitive occurrences of improper torquing requirements resulting from inadequate

personnel work practices, evidenced by leaking connections. Corrective actions, such as

procedure changes and training were taken to address the deficient conditions and to preclude

their recurrence. The applicant stated that independent verification of proper torque values was

also added to work instructions. Subsequent trending data revealed the corrective actions were

effective in precluding the identified conditions. The staff considered the applicant has

adequately identified the cause of the earlier deficient bolting and torquing practice, and has

properly implemented the corrective actions. RAI B.1.2-6 is, therefore, closed.

The staff considered the applicant's operating experience to be an asset to the Bolting and

Torquing Activities Program in managing the loss of mechanical closure integrity. This

operating experience will help minimize recurrence of deficient conditions of closure bolting,

and thus provide assurance that the aging effects associated with bolted closures will be

managed such that applicable structures and components will continue to perform their

intended functions consistent with the current licensing basis for the period of extended

operation.

3-54
UFSAR Supplement

The Bolting and Torquing Activities Program manages the loss of mechanical closure integrity

for bolted connections and bolted closures in high temperature systems and in applications

subject to significant vibration. The program relies on recommendations for a comprehensive

bolting integrity program, as delineated in the Electric Power Research Institute EPRI NP-5067,

Good Bolting Practices. The program also relies on industry recommendations for

comprehensive bolting maintenance, as delineated in the EPRI TR-1 04213, Bolted Joint

Maintenance & Applications Guide.

Conclusion*M

Based on the information provided by the applicant, the staff finds that the Bolting and Torquing

Activities Program is adequate for managing the loss of mechanical closure integrity for bolted

connections and bolted closures in high temperature systems and in applications subject to

significant vibration. On the basis of its review, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplement for.this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.3.3 Heat Exchanger Monitoring Program

Summary of Technical Information in the Application

The applicant's heat exchanger monitoring program is described in LRA Section B.1.12, "Heat

Exchanger Monitoring." In the LRA, the applicant stated that the program is plant-specific and.

will be initiated prior to the period of extended operation. This AMP is credited with inspecting

heat exchangers to detect degradation and, if warranted, evaluating the effects of the_

degradation on the design functions, including seismic operability.;

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.12, of the LRA, regarding the applicant's demonstration of the heat

exchanger monitoring program to ensure that the effects of aging, as discussed above, will beadequately managed so that the intended functions will be maintained consistent with the CLB

throughout the period of extended operation.-

The staff reviewed the heat exchanger monitoring program against the AMP elements found in

the SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1 -1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, 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

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controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

[Scope of the Program] The applicant stated that this program element encompasses

managing aging effects on selected heat exchangers as identified in Section 3 of the LRA. The

staff reviewed Section 3 of the LRA and determined that the heat exchanger monitoring

program is credited with managing aging effects for specific heat exchanger components in the

containment spray and emergency diesel generator systems. The staff confirmed that the

specific components for which the heat exchanger monitoring program manages aging effect

are identified, which satisfies the criterion defined in Appendix A.1 of the SRP-LR. On this

basis, the staff finds that the applicant's proposed scope is acceptable.

[Preventive Maintenance] The applicant stated that this is an inspection program and no

actions are taken as part of this program to prevent degradation. The staff finds that the heat

exchanger monitoring program is a condition monitoring program. It provides early indication

and detection of the onset of aging degradation. It does not rely on preventive actions.

Therefore, staff finds this acceptable.

[Parameters Monitored or Inspected] The applicant stated that non-destructive examinations

will be performed. Eddy current testing will be used to identify wall thinning and cracking in

shell-and-tube heat exchangers. Heat exchanger heads, covers, and tube sheets will be

inspected using visual inspection methods.

The staff noted that although traditional eddy current testing methods can be applied to most

heat exchangers, the shutdown heat exchanger contains ferritic stainless steel tubes.

Traditional eddy current testing methods cannot be used in this application. The applicant

plans to use a testing method similar to eddy current testing that will detect wall thinning and

cracking in these tubes. During the audit, the staff requested details on this inspection

methodology from the applicant. By letter dated January 22, 2004, the applicant provided

details on this methodology.: Specifically, the applicant identified a modified version of eddy

current testing method called remote field testing as the selected technique, and stated that

other appropriate examination techniques may be available at the time of program

implementation and will be based on industry operating experience.

The staff reviewed the applicant's response, and finds that the inspection technique is sufficient

to provide assurance that the aging effects for the components addressed by the heat

exchangers monitoring program will be detected before loss of intended function.

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. The heat exchanger monitoring program is acceptable because the non-destructive

examinations of the heat exchangers are intended to detect the presence and extent of aging

effects. On this basis, the staff finds that the parameters monitored or inspected is acceptable.

[Detection of Aging Effects] The applicant stated, in Appendix B, Section B.1.12 of the LRA,

that

The aging effects being managed by this program for the tubes are loss of material and

cracking. An appropriate sample population of heat exchangers will be determined

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| U
based on operating experience prior to the inspections: The extent and schedule of the

inspections prescribed by the program are designed to maintain seismic qualification

and ensure that aging effects will be discovered and repaired before the loss of intended

function. - U

* The eddy current inspection of the tubes will be every 10 years, or more frequently if

inspection results indicate a need for more frequent inspections. The visual inspections

of the accessible heat exchangers will be performed on the same frequency as the eddy

current inspections. I ! . _' 

* Inspection can reveal cracking and loss of material that could result in degradation in the

seismic qualification of the heat exchangers.- Fouling is not addressed by this program.

The staff noted that, although traditional eddy current testing methods can be applied to most

heat exchanges, the shutdown heat exchanger contains ferritic stainless steel tubes.

Traditional eddy current testing methods cannot be used in this application. The applicant has

developed a testing method, similar to eddy current testing, that will be used to detect wall

thinning and cracking in these tubes. During the audit, the staff requested details on this

inspection methodology from the applicant. By letter dated January 22, 2004, the applicant

provided details on this methodology. Specifically, the applicant identified a modified version of

eddy current testing method called remote field testing as the selected technique, and stated

that other appropriate examination techniques may be available at the time of program

implementation and will be based on industry operating experience. The staff reviewed the

applicant's response, and finds that the inspection technique is acceptable (see discussion

above). X

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Testing techniques will be developed, based on industry operating experience;

sample population of heat exchangers will be determined based on operating experience prior

to the inspections; and eddy current inspection of the tubes will be every 10 years, or more

frequently if inspection results indicate a need for more frequent inspections. On this basis, the

staff concludes that the detection of aging effects is acceptable.

[Monitoring and Trending] The applicant stated, in Appendix B. Section B.1.12, of the LRA, that

the wall thickness of heat exchanger tubing and the material condition of heat exchanger

heads, covers, and tube sheets will be trended. Results will be evaluated against established

acceptance criteria and an assessment will be made regarding the applicable degradation

mechanism, degradation growth rate, and the allowable degradation level. This information will

be used to develop future inspection scope and inspection frequency.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Trending of inspection results will be performed and will enhance the applicant's

ability to detect aging effects before there is a loss of intended function. On this basis, the staff

finds that the monitoring and trending is acceptable. -

[Acceptance Criteria] The applicant stated; in Appendix B, Section B.1.12, of the LRA, that

* The tube plugging limit for each heat exchanger to be eddy-current inspected will be

established based upon a component-specific engineering evaluation. This evaluation

will determine conservative acceptance criteria that will identify when degraded tubes

must be removed from service. - - ,

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M

The acceptance criterion for visual inspections of heat exchanger heads, covers, and

tube sheets will be no 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.

During the audit, the staff requested that the applicant provide specific and detailed acceptance

criteria and its basis for the heat exchanger monitoring program. By letter dated January 22,

2004, the applicant provided the heat exchanger monitoring program specific acceptance

criterion. In its response, the applicant identified that the acceptance criterion for the tube

eddy-current inspections will be wall loss less than 60 percent through wall, which follows the

industry practice that considers this a conservative standard for requiring evaluation of the need

for potential corrective action. In its response, the applicant also stated that the acceptance

criterion for eddy current testing of heat exchanger tubes is conservatively based on a

combination of ASME code requirements and industry practice. The staff reviewed the

applicant's response, and finds it to be acceptable.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Any degradation that could lead to loss of function will be found unacceptable and

corrective measures implemented. On this basis, the staff finds that the acceptance criteria is

acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.12, of the LRA, that

the heat exchanger monitoring program is a new program for which there is no operating

experience. The elements that constitute this program are consistent with years of industry

practice. The applicant stated that the program will be administered under the site quality

assurance (QA) program, which is subject to the requirements of 10 CFR 50, Appendix B.

During the audit, the staff asked the applicant to clarify and/or provide the operating experience

reviews for new programs. In its response, the applicant stated that the plant corrective action

program, which captures internal and external plant operating experience issues, provides

assurance that operating experience will be reviewed and incorporated in the future to provide

objective evidence to support the conclusion that the effects of aging will be adequately

managed.

On the basis of its review of the applicant's response and on discussions with the applicant's

technical staff, the staff concludes that the heat exchanger monitoring program will adequately

manage the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Appendix A, Section A.2.1.13, of the LRA, the applicant provided the UFSAR supplement for

the heat exchanger monitoring program and stated that the program will manage loss of

material and cracking; as applicable, on heat exchangers in various systems. The program will

inspect heat exchangers for degradation using non-destructive examinations, such as

eddy-current inspections and visual inspections. If degradation is found, then an evaluation will

be performed to determine its effects on the heat exchanger's design functions. The applicant

stated in Appendix A that the heat exchanger monitoring program will be initiated prior to the

period of extended operation. The staff reviewed this section and determined that the

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information in the UFSAR supplement provides an adequate summary of the program activities,

as identified in the SRP-LR UFSAR supplement table and as required by 10 CFR 54.21(d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.3.4 Inservice Inspection - Containment Inservice Inspection

Summary of Technical Information in the Application

The applicant's inservice inspection - containment inservice inspection program is described in

LRA Section B.1.13,'"Inservice Inspection - Containment Inservice Inspection." In the LRA, the

applicant stated that the program is plant-specific. The applicant also stated that the program

implements the applicable requirements of the ASME Boiler and Pressure Vessel Code,

Section XI, Subsections IWE and IWL, as modified by 10 CFR 50.55a. Every 10 years the

program is updated to the latest ASME Section XI code edition and addendum approved by the

NRC in 10 CFR 50.55a. The applicant credits the program, under ASME Section XI,

Subsection IWE, with managing loss of material for the steel containment liner and its integral

attachments. The applicant credited the program, under ASME Section Xl, Subsection IWL,

with confirming that the effects of aging on the reinforced concrete containment shell and.

post-tensioning systems will not prevent the performance of intended functions consistent with

the CLB for the period of extended operation.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.13, of the LRA, regarding the applicant's demonstration of the

inservice inspection - containment inservice inspection program to ensure that the effects of

aging, as discussed above, will be adequately managed so that the intended functions will be

maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the inservice inspection - containment inservice inspection program against

the AMP elements found in the SRP-LR,-Appendix A, Section A.1.2.3, and SRP-LR Table A.1-1

and focused on how the program manages aging effects through the effective incorporation of

10 elements (i.e., program scope, 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

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[Scope of Program] The applicant stated that the inservice inspection - containment inservice

inspection program, under ASME Section Xl, Subsection IWE, manages loss of material for the

steel containment liner and its integral attachments. This is within the scope of Subsection

IWE-1000. Under ASME Section Xl, Subsection IWL, the program manages the effects of

aging on the reinforced concrete containment shell and post-tensioning systems to ensure that

they will perform in accordance with the CLB. This is within the scope of Subsection IWE-1 000.

The staff confirmed that the specific components for which the inservice inspection -

containment inservice inspection program are identified. The program scope program element

satisfies the criterion defined in Appendix A.1 of the SRP-LR. On this basis, staff finds that the

applicant's proposed scope is acceptable.

[Preventive Action] The applicant stated that this is a monitoring program that does not include

preventive actions. The staff confirmed that the preventive actions program element satisfies

the criterion defined in Appendix A.1 of the SRP-LR. The staff did not identify the need for

preventive actions for AMP B.1.1 3 because it is a condition monitoring program.

[Parameters Monitored/Inspected] The applicant stated, in Appendix B. Section B.1.13, of the

LRA, that visual inspections for Subsection IWE monitor for corrosion and loss of material of

the steel containment liner and its attachments by inspecting the surface for evidence of flaking,

blistering, peeling, discoloration, and other signs of distress. For Subsection IWL, prestressing

force is measured by lift-off testing or equivalent test which is a TLAA: The staff's review of the

applicant's evaluation of this TLAA is documented in Section 4.5 of this SER. In performing this

review, the staff followed the guidance in Section 4.5 of the SRP-LR.

In addition, the applicant stated that tendon surveillance testing consists of inspection of the

sheathing filler material and anchorage, tendon wire continuity testing, and tendon wire

inspection.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The visual inspections (Subsection IWE) and prestressing force measurements

(Subsection IWL) are intended to detect the presence and extent of aging effects. On this

basis, the staff finds that the parameters monitored or inspected is acceptable.

[Detection of Aging Effects] The applicant stated that the aging effect being managed under

ASME Section Xl, Subsection IWE, is loss of material for the steel containment liner and its

integral attachments. Under ASME Section Xl, Subsection IWL, the program manages the

effects of aging on the reinforced concrete containment shell and post-tensioning system. The

primary inspection method for the steel containment liner and its integral attachments is visual

examination (general visual, VT-3, VT-1). Limited volumetric examination (ultrasonic thickness

measurement) and surface examination (e.g., liquid penetrant) may be necessary in some

instances. The primary inspection method for the concrete containment shell is visual

examination (general, VT-1). The tendon prestressing force is measured by lift-off or

equivalent test. Tendon surveillance testing consists of the sheathing filler material and

anchorage inspection, tendon lift-off force measurement, tendon wire continuity testing, tendon

wire inspection, and tensile testing. The tendon surveillance is performed periodically on a

randomly selected group of tendons to provide confidence in the functional capability of the

system.

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The GALL Report Volume 2, Item IIA.3-1d recommends that examination categories E-B and -

E-F and additional examinations be performed during the period of extended operation to detect

stress corrosion cracking (SCC) of stainless steel and dissimilar metal welds' containment

penetration bellows assemblies. This recommendation is addressed in LRA Table 3.5.1, Item

Number 3.5.1-2. During the audit, the staff noted that these examination categories were not

committed to.

In pursuing this issue, the staff noted that in response to a separate staff RAI 3.5-1, by letter

dated May 19, 2004, the applicant stated that no bellows are used for piping system

containment penetrations. The fuel transfer tube is equipped with bellows type expansion joints

that connect the transfer tube to the liner of the refueling canal in containment and to the liner

of the spent fuel pool in the auxiliary building. The applicant stated that Table 3.5.1, Item

Number 3.5.1-2 of Table 3.5.1 applies to the fuel transfer tube sleeve but not to the bellows

since the bellows is not part of the containment penetration boundary. The bellows connecting

the transfer tube to the refueling canal liner is an extension of the refueling canal liner which,;

has no license renewal intended function. The bellows on the other end of the transfer tube

connects the transfer tube to the liner in the fuel tilt pit portion of the spent fuel pool. The low

point of the opening connecting the spent fuel pool to the tilt pit is above the top of the spent

fuel stored in the storage racks so failure of the bellows cannot result in uncovering of the fuel.

Therefore, neither bellows attached to the fuel transfer tube performs a license renewal

intended function. -

On the basis of its review and of the applicant's response to RAI 3.5-1, the staff confirmed that

this program element satisfies the criteria defined in Appendix A.1 of the SRP-LR. The staff

acknowledges that the frequency and scope of examination specified in 10 CFR 50.55a and

ASME Section Xl, Subsections IWE and IWL, ensure that aging effects will be detected before

they compromise the design basis requirements. .The inspections use a frequency and sample

size based on existing codes and operating experience to detect the presence and extent of

aging effects. On this basis, the staff concludes that the parameters monitored or inspected is

acceptable.

[Monitoring and Trending] The applicant stated, in Appendix B, Section B.1.13, of the LRA, that

that the responsible engineer periodically trends the measured prestressing forces from

surveillances. If this review indicates a trend that would result in the tendon forces for a tendon

or a group of tendons to be less than the minimum prestress value before the next inspection

period, the responsible engineer (or designee) prepares a condition report.

The staff determined that with the exception of inaccessible areas, all metal and concrete

surfaces within the scope are monitored by examination requirements of Subsections IWE and

IWL. Periodically measured tendon prestressing forces are monitored in accordance with the

requirements specified in Subsection IWL and trended to ensure that they remain above theminimum required level. The staff confirmed that this program element satisfies the criteria

defined in Appendix A.1 of the SRP-LR. Trending of the surveillance results will enhance the

applicant's ability to detect aging effects before there is a loss of intended function. On this

basis, the staff finds that the monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated, in Appendix B, Section B.1.13, of the LRA, that the

numerical acceptance standards provided in IWE-3000 for wall thickness and the numerical

values provided in IWL-3000 for post-tensioning systems are utilized. No other numerical

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acceptance standards are provided for the steel containment liner and its integral attachments

or for the reinforced concrete containment. The expertise and engineering judgment of the

responsible engineer are relied upon to detect conditions that could affect the leak-tightness or

structural integrity of the containment or prevent an inspected component from performing its

intended function.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Any wall thickness post-tensioning system values that are projected to fall below

the minimum allowable, as determined by the applicable design code, will be found

unacceptable and corrective measures implemented. On this basis, the staff finds that the

acceptance criteria is acceptable.

[Operating Experience] The staff reviewed the applicant's engineering report related to the

operating experience for this program. Condition report trending data for the period 1998

through 2002 did not identify a need for improvements to this program. The applicant also

stated that the plant corrective action program, which captures internal and external plant

operating experience issues, provides assurance that operating experience will be reviewed in

the future to provide objective evidence to support the conclusion that the effects of aging will

be adequately managed.

The staff agrees that even though limited operating experience was available, the inservice

inspection - containment inservice inspection programs provided assurance that the applicable

aging effects would be adequately managed for the period of extended operation.

UFSAR Supplement

In Appendix A, Section A.2.1.14, of the LRA, the applicant provided the UFSAR supplement for

the inservice inspection - containment inservice inspection program and stated that the

program implements the applicable requirements of ASME Section Xl, Subsections IWE and

IWL as modified by 10 CFR 50.55a. Every 10 years the containment inservice inspection

program for ANO-2 is updated to the latest ASME Section Xl code edition and addendum

approved by the NRC in 10 CFR 50. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the program activities,

as identified in the SRP-LR UFSAR supplement table and as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.3.5 Inservice Inspection - Inservice'inspection

Summary of Technical Information in the Application

The applicant's inservice inspection - inservice inspection program is described in LRA Section

B.1.14, "Inservice Inspection - Inservice Inspection" The applicant stated that this is a

plant-specific program. The applicant credited this program with managing cracking, wear,'loss

of mechanical closure integrity, and loss of 'm-aterial of RCS piping and components, including

RCP items and austenitic stainless steel small bore piping. This program implements the

applicable requirements of the ASME Boiler and Pressure Vessel Code,'Section XIl

Subsections IWB, IWC, IWD, and IWF. In March 2000, ANO-2 entered the third ISI interval

and began implementing the applicable requirements of the 1992 Edition of ASME Section Xl,

with pressure-testing criteria from the 1993 Addenda, approved NRC alternatives and relief

requests, and other requirements specified ini 10'CFR 50.55a.

Staff Evaluation'

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.14, of the LRA, regarding the applicant's demonstration of the

inservice inspection - inservice inspection' program to ensure that the effects of aging, as

discussed above, will be adequately managed so that the intended functions will be maintained

consistent with the CLB throughout the period of extended operation.

The staff reviewed the inservice inspection - inservice inspection program against the AMP

elements found in the SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1-1 and

focused on how the program manages aging^effects through the effective incorporation of 10

elements (i.e., program scope, preventive actions, parameters monitored or inspected,

detecti6ii 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below. '-

[Program Scope] The applicant stated, in Appendix B, Section B.1.14; of the LRA, that the

inservice'inspection program manages cracking, wear,'loss'of mechanical closure integrity, and

loss of material of RCS piping and components, in6luding RCP items and austenitic stainless

steel small bore piping. The inservice inspection program is updated as required to the latest

ASME Section Xl code edition and addendum approved by the NRC in 10 CFR 50.55a. A

risk-informed methodology is used to select Class'1, 2, and 3 piping welds for inspection in lieu

of the requirements specified in the 1992 Edition of the ASME Section Xl.

The staff reviewed the risk-informed inservic&6inspection (RI-ISI) methodology to determine if

this approach is applicable to the period of exterided operation. The applicant stated that there

are no time-dependent parameters used that would change the determination of risk for a-'

component as a result of operating during the license renewal period. The applicant also stated

that any new degradation mechanism or change in consequence of piping failures that occurs

3-63
over the license of the plant, including the period of extended operation, is incorporated into the

RI-ISI program.

In order to evaluate the applicant's position, the staff reviewed the technical bases of the RI-ISI

program and determined that the program scope is capable of managing the identified aging

mechanisms. The applicant demonstrated that the aging effects identified for Class 1 piping

are managed by the RI-ISI program. This was accomplished by identifying all the Class 1

piping aging effects that credit the RI-ISI program for aging management. These aging effects

were compared with the aging effects identified in one of the RI-ISI program bases documents

(EPRI TR-106706). All credited aging effects were found to be included in the program. The

applicant also clarified that although the RI-ISI program addresses Class 1, 2, and 3, only the

Class 1 portion of the risk-informed program is included in the LRA.

The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

the program manages aging. On this basis, the staff finds that the applicant's proposed

program scope is acceptable.

[Preventive Action] The applicant stated that this program element is not applicable because

the inservice inspection - inservice inspection program is an inspection program.

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. The staff did not identify the need for preventive actions for

this program because it is a condition monitoring program.

[Parameters Monitored/Inspected] The applicant stated, in Appendix B, Section B.1.14, of the

LRA, that the program uses non-destructive examination techniques to detect and characterize

flaws. The 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. The VT-1 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 opticaVvideo 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 staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Measurements of wall thickness are intended to detect the presence and extent

of aging effects. On this basis, the staff finds that the parameters monitored or inspected are

acceptable.

3-64
[Detection of Aging Effects] The applicant stated that:

(1) The aging effects being managed by this program are cracking, wear, loss of

mechanical closure integrity, and loss of material of RCS piping, valves and RCP items

including bolting, valve bolting, and flange bolted connections. ASME Section Xl,

Subsection IWB,- examination categories manage the aging effects of the Class 1

piping, valves, and RCP items. This program manages the aging effects through a

combination of visual, surface, and volumetric examinations. Pressure boundary items

undergo a system leakage test including a yisual examination (VT-2) in accordance with

ASME Section Xl requirements.

(2) This program manages cracking of austenitic stainless steel small bore piping. The

applicant defined small bore piping and small bore nozzles as those less than four-inch

nominal pipe size that do not normally receive volumetric inspection in accordance with

ASME Section Xl. This program includes inspection of selected RCS piping welds. The

inspection of RCS piping appropriately addresses cracking of piping greater than

one-inch nominal pipe size for the period of extended operation.

(3) Cracking of the RCP covers is managed by visual examinations conducted in

accordance with ASME Section Xl examination Category B-L-2. Volumetric inspections

of the pump casing welds are no longer, performed at ANO-2 due to implementation of

code case -481. Visual examination of pressure-retaining surfaces is performed in

accordance with ASME Section Xl requirements.

(4) -This program manages cracking of the shell, lower heads and nozzles, and manway

bolting, and supplements the boric acid corrosion prevention program in managing loss

of material at external surfaces of the pressurizer. ASME Section XI, Subsection IWB,

examination categories manage cracking and loss of material of the pressurizer

pressure boundary and support items. This program manages cracking through a

combination of visual, surface, and volumetric examinations.

(5) This program manages cracking of the reactor vessel, lower head, closure head,

nozzles, and reactor vessel bolting, and supplements the boric acid corrosion prevention

program in detecting loss of material at external surfaces of the reactor vessel andcontrol element drive mechanism pressure boundary. ASME Section Xl, Subsection

IWB, examination categories manage cracking and loss of material of the reactor vessel

and control element drive mechanism pressure boundary and support items. In addition

to managing cracking, this program detects degradation as a result of wear. -.Closure.

studs, washers, nuts, and threaded holes of the vessel closure flange are visually

inspected for wear in accordance with ASME Section Xl requirements.

(6) Under ASME Section Xi, Subsection IWB, the program manages cracking, wear, loss of

preload, and loss of material of the. reactor vessel internals items through visual

examinations. Interior attachments and core support structures associated with the

reactor vessel internals undergo a (VT-3) visual examination at the weld (for the

attachments) and at the surface (for the core support structures). . . .- * .

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(7) Under ASME Section Xl, Subsections IWB, IWC, and IWD, the program manages

cracking, wear, and loss of material of the steam generator pressure boundary and

support items through a combination of visual, surface, and volumetric examinations.

(8) Under ASME Section Xl, Subsection IWF, the program manages loss of material for

ASME Class 1, 2, and 3 steel piping supports and steel component supports within the

containment. The program also manages loss of material for steel base plates,

component supports, and threaded fasteners, and cracking for threaded fasteners for

ASME Class 1, 2, and 3 steel piping supports and steel component supports.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The inspections use a frequency and sample size based on existing codes and

operating experience to detect the presence and extent of aging effects. On that basis, the

staff finds the program is capable of detecting aging effects.

[Monitoring and Trending] The applicant stated that this program does not require monitoring

or trending of progressive, time-dependent degradation. Flaws detected are evaluated by

comparing the examination results to the acceptance standards in ASME Section Xl. Flaw

indications require detailed analyses, repair, or replacement. The ISI results are recorded and

provided to the NRC in accordance with ASME Section Xl requirements. Reports describe the

scope of the inspection and significant inspection results.

The staff agreed that the frequency of inspection and the inspection method are specified by

the Code. Indications found by nondestructive examinations are evaluated in accordance with

the Code and, if allowed to remain, will require monitoring and will be used for comparison with

future inservice examination results. This provides for trending of the aging effect and

establishes a baseline for the degradation process and the extent of degradation with time.

The staff accepts this methodology to undertake further programmatic actions, such as repair

and replacement, as necessary, to manage these aging effects.

The staff also confirms that this program element satisfies the criteria defined in Appendix A.1

of the SRP-LR. Trending of the inspection results enhances the applicant's ability to detect

aging effects before there is a loss of intended function. On this basis, the staff finds that the

monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated in Appendix B, Section B.1.14, of the LRA, that if a

flaw is discovered during the performance of an ISI examination, an evaluation is conducted in

accordance with article IWA-3000, IWB-3000, IWC-3000, IWD-3000, or IWF-3000.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff reviewed the applicant's acceptance criteria and finds that any flaws

discovered in the process of performing the inspections are deemed unacceptable and

corrective measures are implemented. On this basis, the staff finds that the acceptance criteria

is acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.14, of the LRA, that

condition report trending data does not identify a need for improvements to this program. A

2002 self assessment evaluated the inservice inspection programs using the NRC Inspections

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Guideline 71111.08, ulnservice Inspection Activities." Minor deficiencies were noted and

resolved during the evaluation.

The applicant also stated that the plant corrective action program, which captures internal and

external plant operating experience issues, provides assurance that operating experience will

be reviewed in the future to provide objective evidence to support the conclusion that the effects

of aging will be adequately managed.

On the basis of its review of the above operating experience on the discussions with the

applicant's technical staff, the staff finds that the inservice inspection - inservice inspection

program adequately manages the aging effects that have been observed at the applicant's

plant and can do so during the period of extended operation.

UFSAR SuDplement

In Appendix A, Section A.2.1.15, of the LRA, the applicant provided the UFSAR supplement for

the inservice inspection program and stated that the program implements the applicable

requirements of ASME Section Xl, Subsections IWB, IWC, IWD and IWF, and other

requirements specified in 10 CFR 50.55a with approved NRC alternatives and relief requests.

Every 10 years the inservice inspection program for ANO-2 is updated to the latest ASME

Section Xl code edition and addendum approved by the NRC in 10 CFR 50. The staff reviewed

this section and determined that the information in the UFSAR supplement provides an

adequate summary of the program activities,; as identified in the SRP-LR UFSAR supplement

table and as required by 10 CFR 54.21(d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.6 Oil Analysis

Summary of Technical Information in the Application

The applicant's oil analysis program is described in Section B.1.17, "Oil Analysis," of the LRA.

In the LRA, the applicant stated that the program is plant-specific. This AMP is credited with

ensuring the oil environment in the mechanical systems is maintained to the required quality.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in LRA

Appendix B, Section B.1.17, of the LRA regarding the applicant's demonstration of the oil

analysis program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.

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A

The staff reviewed the oil analysis program against the AMP elements found in the SRP-LR,

Appendix A, Section A.1.2.3, and SRP-LR Table A.1 -1 and focused on how the program

manages aging effects through the effective incorporation of 10 elements (i.e., program scope,

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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

[Scope of Program] The applicant stated, in Appendix B, Section B.1.17, of the LRA, that the

oil analysis program encompasses periodic sampling of the lubricating oil to which plant

components subject to an AMR are exposed. The purpose of the program is to ensure the oil

environment in the mechanical systems is maintained to the required quality.

The staff also confirmed that the specific components for which the oil analysis program

manages aging are identified and that this program element satisfies the criteria defined in

Appendix A.1 of the SRP-LR. On this basis, the staff finds that the applicant's proposed scope

is acceptable.

[Preventive Actions] The applicant stated that the oil analysis program maintains oil systems

free of contaminants (primarily water and particulates) thereby preserving an environment that

is not conducive to aging mechanisms.

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. The staff finds that the preventive actions program element is

acceptable because maintenance of contaminant-free oil systems prevents and mitigates the

identified aging effects.

[Parameters Monitored/Inspected] The applicant stated that for components with periodic oil

changes in accordance with manufacturer's recommendations, a particle count and check for

water are performed to detect evidence of abnormal wear rates, contamination by moisture, or

excessive corrosion. For components that do not have regular oil changes, viscosity and

neutralization number are also determined to evaluate the oil is suitable for continued use.

The staff reviewed the applicant's program, procedures, and database of lube oil sample

results. The staff confirmed that this program element satisfies the criteria defined in

Appendix A.1 of the SRP-LR. The oil sampling program activities detect the conditions that

potentiate degradation and also detect the presence and extent of aging effects. On this basis,

the staff finds that the parameters monitored or inspected program element is acceptable.

[Detection of Aging Effects) The applicant stated, in Appendix B, Section B. 1.17, of the LRA,

that periodic sampling and compliance with the acceptance criteria provide assurance that lube

oil contaminants do not exceed acceptable levels. This manages the aging effects of cracking,

loss of material, and fouling.

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The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. (Sampling from a population is not applicable to this AMP.) Sampling is

appropriately described and linked to the aging effects and compliance with the acceptance -

criteria allow for the timely detection of their presence and extent. Appropriate industry

standards such as SAE749D, ISO 4406, ISO 112218, and NAS 1638 are used in the

development of sampling methods and frequencies. On this basis, the staff finds that the

detection of aging effects is acceptable.

[Monitoring and Trending] The applicant stated that oil analysis results are reviewed to a

determine if alert levels or limits have been reached or exceeded. This review also checks for

unusual trends. The staff examined the procedures and tools used for this purpose and

considers them to be effective.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff also examined the procedures and tools used for this purpose. --

Trending of the analysis results is performed and enhances the applicant's ability to detect

aging effects before there is'a loss of intended function. On this basis, the staff finds that the

monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated for the oil analysis program that particle

concentration limits are based on industry standards and water concentration will not exceed

0.1%. Viscosity bands are based on a tolerance of 10% around the base viscosity of the

lubricating oil. Metal limits by spectral analysis and ferrography are based on original baseline

data and manufacturer's recommendations.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Any contaminant values that are projected to exceed limits (determined on the

basis of the applicable standards and manufacturers' recommendations documented in the

implementing procedures), result in the implementation of corrective measures. On this basis,

the staff finds the acceptance criteria acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.17, of the LRA, that

condition report trending data does not identify a need for improvements to this program.

The staff has reviewed past test results and noted that the data are maintained within

specifications. That evaluation concluded that the oil analysis program is being implemented as

described in plant procedures and is an effective preventive maintenance program. During the

audit, the staff reviewed more recent data on oil in contact with components subject to aging

management and confirmed that lubricating oils continue to be maintained free of excess water

and contamination. Proper additives remain present to neutralize acids that may form during

component operation.' This operating experience indicates that the program has maintained the

quality of lubricating oils within specified limits to mitigate aging effects that could compromise

the intended functions of components in this environment.

On the basis of its review of the above operating experience and on the discussions with the

applicant's technical staff, the staff finds that the oil analysis program adequately manages the

aging effects that have been observed at the applicant's plant and can do so during the period

of extended operation. ^ -

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UFSAR Supplement

In Appendix A, Section A.2.1.18, of the LRA, the applicant provided the UFSAR supplement for

the oil analysis program and stated that the program ensures the oil environment in mechanical

systems in the scope of license renewal is maintained to the required quality. By monitoring oil

quality, the program maintains oil systems free of contaminants (primarily water and

particulates) thereby preserving an environment that is not conducive to loss of material,

cracking, or fouling. The staff reviewed this section and determined that the information in the

UFSAR supplement provides an adequate summary of the program activities, as identified in

the SRP-LR UFSAR supplement table and as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.7 Periodic Surveillance and Preventive Maintenance

Summary of Technical Information in the Application

The applicant's periodic surveillance and preventive maintenance program is described in LRA

Section B.1.18, uPeriodic Surveillance and Preventive Maintenance." In the LRA, the applicant

stated that the program is plant-specific. This AMP is credited with performing periodic

inspections and tests that are relied on to manage aging effects that are not managed by other

AMPs. The periodic inspections and tests are generally implemented through repetitive tasks

or routine monitoring of plant operations.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.18, of the LRA 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 functions will be maintained

consistent with the CLB throughout the period of extended operation.

The staff reviewed the periodic surveillance and preventive maintenance program against the

AMP elements found in the SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1-1

and focused on how the program manages aging effects through the effective incorporation of

10 elements (i.e., program scope, 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

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seven elements are discussed below.

[Scope of Program] The applicant stated that periodic surveillance and preventive maintenance

program encompasses those tasks credited with managing the aging effects identified in the

AMRs. :The preventive maintenance and surveillance testing activities are generally

implemented through repetitive tasks or routine monitoring of plant operations.

The staff examined the applicant's summary engineering report of aging management reviews

in which the preventive maintenance and surveillance program is credited for the aging

management of a large number of items. Components are identified with this program only if

management of one or more of the aging effects to which they are susceptible is not addressed

in other AMPs. The following systems credit this program for management of aging effects:

(1) emergency core cooling; (2) containment spray; (3) containment cooling; (4) containment

penetrations; (5) EDG; (6) chemical and volume control; (7) alternate AC (AAC) diesel

generator; (8) halon fire protection and RCP motor oil leakage collection; (9) fuel oil;-

(10) service water (SW); (11) auxiliary building ventilation; (12) control room ventilation;

(13) emergency feedwater; (14) auxiliary building, turbine building, and yard structures; and

(15) intake structure and emergency cooling pond.,

The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

the program manages aging. On this basis, the staff finds that the applicant's proposed

program is acceptable.

[Preventive Action] The applicant stated that the inspections and testing activities used to

identify component aging effects do not prevent aging effects. However, the activities are

intended to prevent failures of components that might be caused by aging effects.

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. The periodic surveillance and preventive maintenance

program activities are intended to identified component aging effect and prevent failures of

components that might be caused by aging effects and is consistent with Branch Technical

Position RLSB-1. On this basis, the staff finds the preventive action acceptable.-

[Parameters Monitored/Inspected] :The applicant stated that this program provides instructions

for monitoring SSCs 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 sampled components in the engineered safety features systems and auxiliary

systems. Periodic surveillance and preventive maintenance program activities that are credited

for aging management were reviewed according to their associated repetitive task numbers.

The applicant's commitment tracking system has been invoked to ensure that the surveillance

and preventive maintenance requirements will remain subject to appropriate administrative

controls. The applicant's method of controlling such commitments was examined in sufficient

detail to permit confidence that once correctly identified, parameters relevant to extended

operation would be monitored as required.-: Forthose components audited, the parameters

monitored were reviewed and determined to be closely linked to the intended function of

components managed under the periodic surveillance and preventive maintenance program.

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The inspection and testing activities are planned so as to detect the presence and extent of

aging effects.

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. On the basis of interviews with the applicant's technical staff, the staff finds the

applicant's parameters monitored or inspected to be acceptable.

[Detection of Aging Effects] The applicant stated, for the periodic surveillance and preventive

maintenance program, that

(1) Preventive maintenance activities provide for periodic component inspections and

testing to detect aging effects. Inspection intervals are established such that they

provide for timely detection of degradation. Inspection intervals are dependent on the

component material and environment and take into consideration industry and

plant-specific operating experience and manufacturer's recommendations.

(2) 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.

(3) Containment spray system pump seal heat exchanger testing manages fouling on the

borated water side of the heat exchanger tubing. Containment sump inspection

manages loss of material on stainless steel components in the containment sump.

Emergency diesel generator maintenance inspections manage loss of material

(including that due to selective leaching), cracking, fouling, and change in material

properties for various materials. Emergency diesel generator surveillance testing

manages fouling on air and treated water sides of the EDG air cooler heat exchangers.

Chemical and volume control system periodic surveillance testing manages loss of

material of charging pump casings. MC diesel generator maintenance inspections

manage loss of material (including that due to selective leaching), cracking, and change

in material properties for various materials. AAC diesel generator surveillance testing

manages fouling on heat exchanger tubing of the engine cooling water radiator,

aftercooler heat exchanger, and lube oil heat exchanger. The CPC room halon system

visual inspection manages loss of material for external and internal surfaces of carbon

steel components. The RCP motor oil leakage collection system visual inspection

manages loss of material for carbon steel and stainless steel components. Maintenance

inspections of fuel oil system components manage loss of material, cracking, and

change in material properties for various materials. Diesel generator surveillance

testing manages fouling on the heat exchanger tubing of the diesel fuel oil return cooler.

Service water system surveillance testing manages loss of material on bolting, filters,

and pump casings. Auxiliary building ventilation system testing manages fouling on both

the water and air sides of copper alloy cooling coils, and loss of material for external

copper alloy cooling coil surfaces and for internal surfaces of the carbon steel cooling

coil housing. Auxiliary building ventilation system testing manages change in material

properties and cracking of elastomer flexible connections. Control room ventilation

system testing manages loss of material and fouling for copper alloy, carbon steel, and

stainless steel components. Control room ventilation system testing manages cracking

and change in material properties of elastomer flexible connections. Emergency

feedwater system testing and inspections manage loss of material and fouling on carbon

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steel and copper components in the emergency feedwater system. Battery rack

inspection manages loss of material for in-§cope battery' tacks.

(4) Low pressure safety injection (LPSI) and high-pressure safety injection (HPSI) pump

surveillance testing currently manages fouling on the borated water side of heat

exchanger tubing of LPSI and HPSI pump seal coolers and fouling on the raw water

-side of HPSI pump bearing housings internal surfaces. For license renewal, the

--program will additionally inspect the interior of the bearing housings for the HPSI pumps

for loss of material (including that due to selective leaching). Acceptance criteria and

corrective actions for this enhancement will be specified.;

(5) Periodic inspection of the external (air) side of containment SW cooling coils currently

-manages fouling and loss of material for the copper alloy cooling coils. For license

renewal, the work orders for cleaning and inspecting the cooling coils of 2VCC-2A/B/C/D

will be enhanced to include inspections to confirm the following conditions: no corroded

parts or areas; and no accumulation of dirt or sludge that would affect the cooling ability

of the coils.;

(6) Periodic inspection of the interior and exterior of the cooling coil housing currently

*manages the effect of loss of material on carbon and stainless steel components.,This

l;includes inspection of the housing floor, coils, coil mounting bolts, frame, drain pans,

and flanges. For license renewal, the 'work orders for cleaning and inspecting the.

housings of 2VCC-2A/B/C/D will be enhanced to include inspections of the interior and

exterior of the housings to confirm the following conditions: no degradation of housing

floor that would impact seismic qualification or affect required pressure boundary; no

loose or degraded upper or lower c oil mounting fasteners that would allow the coil to fall

*and block the drop-out dampers if an earthquake were to occur; and no significant

.corrosion or degradation of exterior surfaces, including the flanges of the SW coils, that

could affect coil seismic qualification, -required pressure boundary, or the ability to.

-transfer the required heat load. -

(7) During the monthly electrical penetration nitrogen leak rate test, if bottle pressure is too

low, the bottles are replaced. The elastomer flex hoses in the electrical penetration

nitrogen pressurization system are checked for cracking and change in material-.

properties during replacement of nitrogen bottles.

(8) Annual emergency cooling pond sounding manages loss of form for the emergencycooling pond natural soils. Accessible and exposed surfaces are visually inspected

*-,along with sounding for pond level. Areas of the cooling pond are inspected for,

excessive erosion, degradation of -riprap,, or~ silt buildup.,

During its review, the staff requested that the applicant identify how specific aging effects are,,

detected and the associated technical basis, because different aging mechanisms require:

diff erent detection methods. -The staff requested that the applicant provide the emergency

diesel generator maintenance inspections and emergency diesel generator surveillance testing

as examples.;

In its response dated July 22, 2004, the applicant provided a table listing the aging effect

detection methods for aging eff ects such as lo~ss of material (including that due to selective

.3-73
leaching), cracking, fouling, and change in material properties, and the technical basis for

emergency diesel generator maintenance inspections. On the basis that the applicant provided

adequate technical justification for the aging effect detection methods, the staff finds this

acceptable.

Additionally, the staff asked the applicant to clarify, with regard to the chemical and volume

control system (CVCS) periodic surveillance testing, what specific inspections or tests are

conducted to assure that aging is not occurring in the charging pump casings, and to identify

the frequency and acceptance criteria applicable to this surveillance testing. The staff also

asked the applicant to identify specific criteria and operating experience that demonstrate loss

of material in the charging pump casings is being effectively managed.

In its response dated July 22, 2004, the applicant provided the parameters monitored, detection

of aging effects, monitoring and trending, acceptance criteria, and operating experience for loss

of material due to wear and cracking due to fatigue aging effects for the CVCS charging pump

casings. On the basis that the applicant provided the inspections and tests, acceptance criteria,

and operating experience related to loss of material and cracking aging effects for the CVCS

charging pump casings, the project team finds this acceptable.

The staff observed that measurements and inspections of other selected systems' surveillances

use a frequency and sample size based on operating experience to detect the presence and

extent of aging effects. The staff confirmed that this program element satisfies the criteria

defined in Appendix A.1 of the SRP-LR. On the basis of its review of the applicant's responses,

the staff finds that the detection of aging effects is acceptable.

[Monitoring and Trending] The applicant stated that preventive maintenance 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 the component material and

environment and take into consideration industry and plant-specific operating experience and

manufacturers' recommendations.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff noted that there are specific activities that will not be within the scope of

the program until the license is renewed. The staff reviewed the applicant's commitment

management program, which is used to ensure that these changes will be properly

implemented, as well as the specific record originated to track the implementation of

modifications necessitated by license renewal. Trending of the inspection results will enhance

the applicant's ability to detect aging effects before there is a loss of intended function. On the

basis of its review of the monitoring and trending, the staff finds it acceptable.

[Acceptance Criteria] The applicant stated that the periodic surveillance and preventive

maintenance program acceptance criteria are defined in specific inspection and testing

procedures. The acceptance criteria confirm component integrity by evaluating the absence of

aging effect or by comparing applicable parameters to limits based on applicable intended

functions established by the plant design basis.

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. The staff reviewed a selection of the repetitive tasks and associated procedures. In

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all cases where an aging effect had been identified, appropriate acceptance criteria were

provided. While this offers some confidence that additional aging effects will be appropriately

monitored, the codes and/or standards to be applied (and methods of assessment) have yet to

be specified for the full license renewal scope. On the basis of its review of the applicant's

acceptance criteria prograrmi element, the staff finds that any degradation to component integrity

below the minimum allowable is unacceptable-and corrective measures are implemented. On

this basis, the staff finds the acceptance'criteria program element to be acceptable.

[Operating Experience] The applicant stated that the plant's history of successful operation

demonstrates that typical surveillance and preventive maintenance activities have been

effective in managing the effects of aging on components.

The staff reviewed the applicant's programmatic experience with surveillance and maintenance

activities. Although numerous deficiencies were identified, corrective actions were implemented

and their effectiveness has been documented.' This supports the conclusion that the program

has been effective and will support license renewal. -The applicant also stated that the plant

corrective action program, which captures internal and external plant operating experience

issues, provides assurance that operating experience will be reviewed in the future to provide

objective evidence to support the conclusion that the effects of aging will be adequately :

managed. On the basis of its review of the above operating experience and on discussions

with the -applicant's technical staff, the staff concludes that the periodic surveillance and

preventive maintenance program adequately manages the aging effects that have been

observed at the applicant's plant. -

UFSAR Supplement

In Appendix A, Section A.2.1.19, of the LRA, the applicant provided the UFSAR supplement for

the periodic surveillance and preventive maintenance program and stated that the program

consists of periodic inspections and tests that are relied on to manage aging effects that are not

managed by other AMPs. Preventive maintenance and surveillance testing activities provide for

periodic component inspections and testing to detect various aging effects applicable to those

components included in the program for license renewal. The staff reviewed this section and'

determined that the information in the UFSAR supplement provides an adequate summary of

the program activities, as identified in the SRP-LR UFSAR supplement table and as required by

10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). - - ; -

The staff also reviewed the UFSAR supplemen't for this AMP and finds that it provides an

adequate summary description of the program,'as required by 10 CFR 54.21 (d).

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3.0.3.3.8 Pressurizer Examinations Program

Summary of Technical Information in the Application

The applicant's pressurizer examinations program is described in LRA Section B.1.19,

'Pressurizer Examinations." In the LRA, the applicant stated that the program is plant-specific.

The AMP is credited with identification of pressurizer cladding cracking, which could potentially

cause loss of intended function of the pressurizer.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.19, of the LRA, regarding the applicant's demonstration of the

pressurizer examinations program to ensure that the effects of aging, as discussed above, will

be adequately managed so that the intended functions will be maintained consistent with the

CLB throughout the period of extended operation.

The staff reviewed the pressurizer examinations program against the AMP elements found in

the SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

[Program Scope] The applicant stated, in Appendix B, Section B.1.19, of the LRA, that the

pressurizer examinations program will manage cracking of the stainless steel and nickel-based

alloy cladding and attachment welds to the cladding of the pressurizer by examination of the

adjacent base metal. The pressurizer shell and upper head are clad with austenitic stainless

steel. The lower head is clad with nickel-based alloy.

During the audit, in RAI B.1.19-1, the staff asked the applicant to confirm that the pressurizer

examinations program comprises activities performed under the existing inservice inspection

program, and if it is an existing program, to update the UFSAR supplement, LRA Section

A.2.1 .20.

In its response to RAI B.1.19-1, by letter dated July 22, 2004, the applicant stated that the

pressurizer examinations program comprises activities performed under the existing inservice

inspection program and that, upon incorporation into the safety analysis report, the UFSAR

supplement LRA Section A.2.1.20 will be revised to indicate that the pressurizer examinations

program is an existing program. On the basis of its review of the applicant's response, the staff

finds this acceptance, and the RAI is resolved.

The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

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the program manages aging. On this basis,'the staff finds that the applicant's proposed

program scope is acceptable. -

[Preventive Actions] The applicant stated the pressurizer examinations program is an

inspection program and that no actions will be taken as part of this program to prevent aging

effects or mitigate aging degradation. However, the applicant added that the its water

chemistry control program includes effective actions to avoid SCC of the cladding and

attachment welds. -

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. The staff did not identify the need for preventive actions for

this program because it is a condition monitoring program.

[Parameters Monitored] The applicant stated that (1) in order to provide assurance that

cracking of the pressurizer cladding has not propagated into the underlying base metal of the

pressurizer, volumetric examination of pressurizer items that are susceptible to cracking will be

performed. Cracking of the pressurizer stainless steel cladding would most likely result from

thermal fatigue and cracking of the nickel-based alloy cladding would most likely result from

primary water SCC and fatigue. The pressurizer pressure boundary items with high fatigue

cumulative usage factors include the circumferential weld at the head-to-shell junction and the

surge nozzle to shell junction and (2) in accordance with ASME Section Xl, Examination - -

Category B-B, volumetric examination of essentially 100% of the circumferential shell-to-head

weld will be performed. In addition, the weld metal between the surge nozzle and the vessel

lower head will be subjected to high stress cycles' Periodic monitoring of this area provides

monitoring for cracking of the nickel-based alloy cladding that may propagate to the underlying

ferritic steel. The weld that connects the surge nozzle to the lower head will receive volumetric

examination in accordance with Examination Category B-D. These examinations will continue

through the period of extended operation to manage cracking of cladding that may extend into

the base metal at susceptible locations. -

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. The evaluations of cladding and weld integrity are intended to detect the presence

and extent of aging effects. On this basis, the staff finds that the parameters monitored or

inspected are acceptable.

[Detection of Aging Effects] The applicant stated that detection of cracking in the pressurizer

cladding will be achieved through periodic volumetric inspections of the base metal as required

by ASME Section Xl. Inspection of these items constitutes an appropriate sample of the

remaining stainless steel and nickel-based alloy clad items in the pressurizer. Information in

Table IWB 2500-1 describes the inspection sampling requirements, the examination methods,

and the examination frequencies for the pressurizer. Detection of cracking will be achieved

through periodic volumetric inspections as required by ASME Section Xl.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The applicant stated that inspections will use a frequency and sample size'based

on existing codes and operating experience, to detect the presence and extent of aging effects.

On this basis, the staff finds 'that the detection of aging effects is acceptable.

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0

[Monitoring and Trending] The applicant stated that (1) during the course of the inspections,

the extent of surface or volumetric flaws will be characterized by non-destructive examinations.

Anomalous indications that are signs of degradation will be recorded on non-destructive

examination reports in accordance with plant procedures and (2) the corrective action program

and the requirements of ASME Section Xl will address trending of flaws detected.

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect aging

effects before there is a loss of intended function. On this basis, the staff finds that the

monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated that acceptance criteria for volumetric examinations

will be in accordance with ASME Section Xl, IWB-3510 and IWB-3512.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff finds that any volumetric examination results that fall below the

minimum allowable, as determined by the applicable design code, will be found unacceptable

and corrective measures implemented. On that basis, the staff finds that the acceptance

criteria is acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.19, of the LRA, that

its pressurizer examinations program is a new program for which there is no operating

experience. The program will include volumetric examinations of pressurizer items having high

susceptibility to thermal fatigue. Cracking of the cladding that extends into the base metal will

be detected by ASME Section Xl volumetric examinations at these locations. The volumetric

inspections will be performed with ISI techniques that have been proven effective within the

industry at detecting cracking before loss of function occurs.

In the LRA, the applicant stated that the program is based on proven ISI techniques that can

effectively manage cracking of pressurizer cladding. This program will provide assurance that

the aging effects will be managed so that the pressurizer will continue to perform its intended

functions consistent with the CLB for the period of extended operation.

During the audit, the staff asked the applicant to clarify and/or provide the operating experience

reviews for new programs. In its response, the applicant stated that the plant corrective action

program, which captures internal and external plant operating experience issues, provides

assurance that operating experience will be reviewed and incorporated in the future to provide

objective evidence to support the conclusion that the effects of aging will be adequately

managed.

The staff agrees that even though limited operating experience was available, the pressurizer

examinations program provided assurance that the applicable aging effects would be

adequately managed for the period of extended operation.

UFSAR Supplement

In Appendix A, Section A.2.1.20, of the LRA, the applicant provided the UFSAR supplement for

the pressurizer examinations program and stated that the program will use volumetric

examinations required by ASME Section Xl to manage cracking of the stainless steel and

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nickel-based alloy cladding and attachment welds to the cladding which may propagate into the

underlying ferritic steel. Volumetric examination of the circumferential shell-to-head weld and

the weld metal between the surge nozzle and the vessel lower head will be performed each ISI

inspection interval. The applicant stated in Appendix A that the pressurizer examinations

program will be implemented prior to the period of extended operation. As stated in its

response to RAI B.1.19-1, the applicant stated that UFSAR supplement A.2.1.20 will be revised

to indicate that the pressurizer examinations program is an existing program. The staff

reviewed this section and determined that the information in the UFSAR supplement provides

an adequate summary of the program activities, as identified in the SRP-LR UFSAR

supplement table and as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.9 System Walkdown Program

Summary of Technical Information in the ApDplication

The applicant's system walkdown program is described in LRA Section B.1.28, "System

Walkdown." In the LRA, the applicant stated that the program is plant-specific. The AMP is

credited with managing aging effects on systems and components within the scope of license

renewal and subject to aging management review.

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in

Appendix B, Section B.1.19, of the LRA, regarding the applicant's demonstration of the system

walkdown program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.,

The staff reviewed the system walkdown program against the AMP elements found in the

SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1 -1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER.1 The remaining

seven elements are discussed below. - ' -

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[Program Scope] The applicant stated, in Appendix B, Section B.1.28, of the LRA, that the

system walkdown program includes inspections of external surfaces of ANO-2 components

within the scope of license renewal and subject to an aging management review. The program

is credited with managing loss of material from internal surfaces for situations in which the

external surface condition is representative of the internal surface condition and both have the

same environment. The program is also credited with detecting leakage and spray from

liquid-filled low-energy systems before such leakage can prevent satisfactory accomplishment

of safety functions.

The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

the program manages aging. On this basis, the staff finds that the applicant's proposed

program scope is acceptable.

[Preventive Actions] The applicant stated that the system walkdown program is an inspection

program and no actions will be taken as part of this program to prevent or mitigate aging

degradation.

The staff confirmed that the program element satisfies the criterion defined in Appendix A.1 of

the SRP-LR. The staff did not identify the need for preventive actions since the system

walkdown program is a condition monitoring program.

[Parameters Monitored/Inspected] The applicant stated that during a walkdown, the engineer

monitors for items which could affect system performance, safety, or reliability as well as

general housekeeping, personnel safety hazards, and radiological concerns. Examples of

parameters inspected during the system walkdown are condition and placement of coatings,

evidence of corrosion, and indications of leakage.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The system walkdown activities are intended to detect the presence and extent of

aging effects. On this basis, the staff finds that the parameters monitored or inspected is

acceptable.

[Detection of Aging Effects] The applicant stated (1) a general visual inspection is conducted

on readily accessible system and component surfaces during walkdowns, (2) component

walkdowns are performed periodically at a frequency dependent on the component being

inspected and (3) for each system that credits the program, system engineers are expected to

perform a walkdown at least once per refueling cycle. The frequency of inspection is

acceptable because aging effects are typically caused by relatively long-term degradation

mechanisms such as corrosion.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of.

the SRP-LR. The walkdowns are conducted, using a frequency and sample size based on

operating experience, to detect the presence and extent of aging effects. On that basis, the

staff finds that the detection of aging effects is acceptable.

[Monitoring and Trending] The applicant stated that (1) the program uses standardized

monitoring and trending activities to track degradation. Deficiencies are documented so that

results can be trended. In addition to preparing a written description and noting the location,

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this may also include collecting measurements to determine the severity of deterioration, taking

photographs, or drawing sketches and (2) component inspections are conducted by qualified

engineers using predefined checklists. Personnel are qualified in accordance with the

engineering support personnel training program that provides assurance of an appropriate level

of knowledge and experience' prior to performing engineering activities.'

The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect aging

effects before there is a loss of intended function. On this basis, the staff finds that the

monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated that, for the system walkdown program, all

unacceptable visual indications of cracking, loss of material, or change of material properties of

components are documented as deficiencies.,

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff finds that any deficiencies will be found unacceptable and corrective

measures implemented. On this basis, the staff finds that the acceptance criteria is acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.28, of the LRA, that

the condition reports document conditions identified during walkdowns, including instances of

corrosion, paint flaking, excessive wear, plant environment issues, leakage, loose parts', bent or

broken parts, and numerous other material conditions. Condition report trending data did not

identify a need for improvement to this program. -Operating experience demonstrated that

under the program coating deficiencies, evidence of corrosion, and indications of leakage were

being adequately detected and corrective action was initiated as required. The applicant also

stated that the plant corrective action program, which captures internal and external plant -, I

operating experience issues, provides assurance that operating experience will be reviewed in

the future to provide objective evidence to support the conclusion that the effects of aging will

be adequately managed.

On the basis of its review of the above operating experience on the discussions with the

applicant's technical staff, the staff finds that the system walkdown program adequately

manages the aging effects that'have been observed at the applicant's plant and can do so

during the period of extended operation.--

UFSAR Supplement

In Appendix A, Section A.2.1.29, of the LRA; the applicant provided the UFSAR supplement for

the system walkdown program and stated that the program conducts inspections to manage

loss of material, loss of mechanical closure integrity, and cracking,- as applicable, for SCs within

the scope of license renewal. The program uses general visual inspections of readily

accessible system and component surfaces during system walkdowns.' -The staff reviewed this

section and determined that the information'in the UFSAR supplement provides an adequate

summary of the program activities, as identified in the SRP-LR UFSAR supplement table and

as required by 10 CFR 54.21 (d).

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Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.10 Wall Thinning Monitoring Program

Summary of Technical Information in the Application

The applicant's wall thinning monitoring program is described in LRA Section B.1.29, "Wall

Thinning Monitoring." In the LRA, the applicant stated that the program is plant-specific and is

credited with ensuring that wall thickness is above the minimum required in order to avoid

failures under normal, transient, and accident conditions, including seismic events.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.19, of the LRA, regarding the applicant's demonstration of the wall

thinning monitoring program to ensure that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB throughout the period of

extended operation.

The staff reviewed the wall thinning monitoring program against the AMP elements found in the

SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR, Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope,.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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

[Scope of Program] The applicant stated, in Appendix B, Section B.1.29, of the LRA, that the

wall thinning monitoring program encompasses wall thinning monitoring inspections for carbon

and stainless steel components.

The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

the program manages aging. On this basis, the staff finds that the applicant's proposed

program scope is acceptable.

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[Preventive Actions] The applicant stated the wall thinning monitoring program is an inspection

program and no actions will be taken as part of this program to prevent or mitigate degradation.

due to aging.

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. The staff did not identify the need for preventive actions for the

wall thinning monitoring program since it is a condition monitoring program.:E

[Parameters Monitored] The applicant stated that non-destructive examinations will be

performed on susceptible components to determine wall thickness.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. During the audit, the staff observed that the applicant did not identify the

parameters monitored nor the type of non-destructive examinations to be performed. By letter

dated January 22, 2004, the applicant stated that the wall thinning program was modified to

identify that the parameter monitored will be wall thickness. In its letter, the applicant also

stated that the wall thinning program was modified to reflect that non-destructive examinations

using industry-accepted methods such as ultrasonictesting will be performed on susceptible

components to determine wall thickness. The parameters monitored or inspected program.

element is acceptable because the measurements of wall thickness are intended to detect the

presence and extent of aging effects. On this basis, the staff finds that the parameters

monitored or inspected is acceptable.

[Detection of Aging Effects] The applicant stated that (1) the aging effect being managed by:

this program is loss of material. An appropriate sample size will be determined based on

operating experience prior to these inspection activities. -The extent and schedule of the

examinations prescribed by the program rwill be designed to ensure that aging effects will be

discovered and repaired before loss of intended function and (2) inspections will be performed

periodically at a frequency to be determined prior to implementation. The frequency of

inspections will depend upon results of previous inspections, calculated rate of material loss,

and industry and plant operating experience.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. However, the staff observed that applicant did not specify the type of

non-destructive examinations to be performed. By letter dated January 22, 2004, the applicant

stated that the wall thinning program was modified to reflect that non-destructive examinations

using industry-accepted methods such as ultrasonic testing will be performed on susceptible

components to determine wall thickness., The staff finds, based on its review of the detection of

aging effects program element and the applicant's -January 22, 2004 letter, that the detection of

aging effects program element is acceptable because the inspections will be developed, using a

frequency and sample size based on operating experience, to detect the presence and extent

of aging effects. With this additional information the staff finds that the criteria of SRP-LR

Appendix A.1 are satisfied and so the program element is acceptable.

[Monitoring and Trending] The applicant stated that wall thickness will be trended and

projected to the next inspection, and corrective actions will be taken if the projections indicate

that the acceptance criteria of minimum wall thickness may not be met at the next inspection. V .- A ! - - . .

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The staff confirmed that this program element satisfies the criteria defined in Appendix A of the

SRP-LR. Trending' of the inspection results will 'enhance the applicant's ability to detect aging

effects before there is a loss of intended function. On this basis, the staff finds that the

monitoring and trending is acceptable.

[Acceptance Criteria] The applicant stated that wall thickness measurements greater than

minimum wall thickness values for the components' design code of record will be acceptable.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. The staff finds that any wall thickness values that are projected to fall below the

minimum allowable, as determined by the applicable design code, will be found unacceptable

and corrective measures implemented. On this basis, the staff finds that the acceptance

criteria is acceptable.

[Operating Experience] The applicant stated, in Appendix B, Section B.1.29, of the LRA, that

wall thinning monitoring program is a new program for which there is no operating experience.

The staff observed that ultrasonic wall thickness examinations are consistent with industry

standards and the applicant had indicated that if initial or periodic examinations reveal the need

to expand the sample size or increase the frequency of these activities, such actions would

occur. The operating experience associated with the wall thinning monitoring program will be

accrued over the period of extended operation.

During the audit, the staff asked the applicant to clarify and/or provide the operating experience

reviews for new programs. In its response, the applicant stated that the plant corrective action

program, which captures internal and external plant operating experience issues, provides

assurance that operating experience will be reviewed and incorporated in the future to provide

objective evidence to support the conclusion that the effects of aging will be adequately

managed.

The staff agrees that even though limited operating experience was available, the wall thinning

program provides assurance that the applicable aging effects would be adequately managed

for the period of extended operation.

UFSAR Supplement

In Appendix A, Section A.2.1.30, of the LRA, the applicant provided the UFSAR supplement for

the wall thinning monitoring program and stated that it will manage loss of material from'

components, as applicable, within the scope of license renewal. Inspections will be performed

to ensure wall thickness is above the minimum required in order to avoid failures. The applicant

stated in Appendix A that the wall thinning monitoring program will be initiated prior to the

period of extended operation. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary of the program activities,

as identified in the SRP-LR UFSAR supplement table and as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

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functions will be maintained consistent with the CLB 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 finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.3.11 Auxiliary Systems Water Chemistry Control Program

Summary of Technical Information in the Application

The applicant's auxiliary systems water chemistry control program is described in LRA Section

B.1.30.1,,"Auxiliary Systems Water Chemistry Control." In the LRA, the applicant stated that

the program is plant-specific and is credited with managing loss of material, cracking, and

fouling of components exposed to treated water environments.

Staff Evaluation -

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in

Appendix B, Section B.1.30.1, of the LRA, regarding the applicant's demonstration of the

auxiliary systems water chemistry control program to ensure that the effects of aging, as :

discussed above, will be adequately managed so that the intended functions will be maintained

consistent with the CLB throughout the period of extended operation.

The staff reviewed the auxiliary systems water chemistry control program against the AMP

elements found in the SRP-LR, Appendix A;-Section A.1.2.3 and SRP-LR Table A.1-1 and

focused on how the program manages aging effects through the effective incorporation of 10

elements (i.e., program scope, 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 are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below.

[Scope of Program] The applicant stated, in Appendix B, Section B.1.30.1, of the LRA, that the

auxiliary systems water chemistry control program encompasses sampling activities that include

analyses on the EDG and MC diesel generator cooling water systems. In addition, the -

program includes chemistry monitoring and inspection activities on selected systems included in

the scope of license renewal due to possible spatial interactions with safety-related systems.

These are systems containing treated water that are not covered by other chemistry programs.

The applicant stated that LRA Section 2.3.3.11 contains the non-safety-related SCs. In Section

2.3.3.11 of the LRA, the applicant described the systems that are in-scope for 10 CFR

54.4(a)(2). Specifically, LRA Table 2.3.3-11; "Miscellaneous Systems in scope for 10 CFR

54.4(a)(2) Components Subject to Aging Management Review," described non-safety-related

system components. LRA Table 3.3.2-11; 'Miscellaneous Systems in scope for 10 CFR

54.4(a)(2) Summary of Aging Management Evaluation," identifies component types that credit

the auxiliary systems water chemistry control program as an AMP.

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The staff confirmed that the program scope program element satisfies the criterion defined in

Appendix A.1 of the SRP-LR. The proposed scope identifies the specific components for which

the program manages aging. On this basis, the staff finds that the applicant's proposed

program scope is acceptable.

[Preventive Actions] The applicant stated that this program monitors and controls water

chemistry in the cooling water systems to manage the effects of aging.

The staff confirmed that the preventive actions program element satisfies the criterion defined

in Appendix A.1 of the SRP-LR. On the basis of its audit of the implementation procedures and

review of the program basis documents, the staff finds that preventive actions program element

is acceptable because it identifies and describes the activities from managing aging effects.

[Parameters Monitored/Inspected] The applicant stated that the program inspects components

for visible corrosion, deposits, structural damage, and biological growth. The systems are

inspected when opened for maintenance. The program typically monitors pH, conductivity,

solids, hardness, nitrite, freeze point, and biological count.

During its audit, the staff asked the applicant to (1) clarify whether iron and copper are

monitored in the applicant's auxiliary systems water chemistry control program, and (2) discuss

whether the parameters monitored/inspected under this program are consistent with the

industry guidance credited. The applicant stated that iron and copper are monitored under the

program, and that the program covers a wide variety of equipment and parameters that are

monitored/inspected in accordance with vendor recommendations for the individual

components. The component inspections and water chemistry monitoring activities are

intended to detect the presence and extent of aging effects.

During its audit, the staff asked the applicant to (1) discuss the systems and components that

have been inspected (i.e., scope of inspection) under the auxiliary system water chemistry

control program (AMP B.1.30.1) in the past and which systems and components would be

inspected during the extended period of operation; and (2) discuss whether any systems

covered under this program have never been inspected and whether component failures (e.g.,

leakage) have occurred in these systems.

In its response dated May 19, 2004, the applicant stated that visual inspections have been

performed on components in the emergency diesel generator, condensate storage, feedwater,

chilled water, and main steam systems during disassembly for various reasons. A number of

components such as piping, tanks, heat exchangers and valves that are managed by the

auxiliary systems water chemistry control program have been inspected on both the emergency

diesel generators and the AAC diesel generator. Many of the components in these cooling

water systems are subject to inspection on a routine basis and, as a result, will be

inspected during the period of extended operation.

In its response dated May 19, 2004 to the second question above, the applicant stated that

during operation, all systems with components that rely only on the auxiliary systems water

chemistry control program for managing aging effects have been inspected during

maintenance. If leakage were to occur in a system covered by this program, it would have

been opened during maintenance to repair the leak and, therefore, would have been inspected.

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On the basis of its review of the applicant's responses, the staff confirmed that this program

element satisfies the criteria defined in Appendix A.1 of the SRP-LR and finds that the

parameters monitored or inspected program element is acceptable.

[Detection of Aging Effects] The applicant stated that this program manages aging effects in

the systems included in the scope. -

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR: In its engineering report, the applicant stated that the aging effects being

managed include loss of material (including that due to selective leaching) from the

components containing treated water in the emergency diesel generator system; fouling of the

heat exchanger tubes of the emergency diesel generator system; loss of material (including that

due to selective leaching) from the alternate AC diesel generator components exposed to

treated water; fouling on the heat exchanger tubes of the alternate AC diesel generator system;

and loss of material and cracking for certain systems containing treated water. The staff

reviewed the engineering'report, and finds'that the component inspections are conducted to

detect the presence and extent of aging effects. On this basis, the staff finds that the detection

of aging effects program element is acceptable.

[Monitoring and Trending] The applicant stated that values from analyses are archived for

long-term trending and review.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect - aging effects before there is a loss of intended function. On this basis, the staff finds that the

monitoring and trending are acceptable.

[Acceptance Criteria] The applicant stated that the'acceptance criteria for chemistry

parameters are in accordance with the manufacturer's recommendations or industry guidance.

The acceptance criteria for visual inspections'are'satisfactory general cleanliness and no

unacceptable corrosion, deposits, or structural damage.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 of

the SRP-LR. 'The staff finds that any inspection results that indicate component degradation or

any chemistry parameters that fall outside those contained in applicable industry and

manufacturers' guidelines will be found unacceptable and corrective measures implemented.

During the audit, the staff asked the applicant to identify specific industry guidance documents

used as the basis for the acceptance criteria.

In its response dated May 19, 2004, the applicant replied that EPRI TR-1 07396 was used to

develop the auxiliary systems water chemistry control program and implementing procedure

1052.027. The applicant further stated that more specific guidance was also used to develop

the program, including EPRI NP-5569,' Chromate Substitutes for Corrosion Inhibitors in

Cooling Systems'; CE-NPSD-448, 'Review of Inhibitors used in Closed Cycle Cooling Water.

Systems'; EPRI TR-105504, "Primer on Maintaining the Integrity of Water-Cooled Generator

Stator Windings"; and the 'Technical Manual for Alternate AC Diesel Generator System.

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On the basis of the applicant's response to the above question and its review, the staff finds the

acceptance criteria acceptable.

[Operating Experience] The applicant stated that during the review of the ANO-1 LRA

(OCNA040109), the NRC staff reviewed the ANO auxiliary systems water chemistry control

program. The governing procedure for the auxiliary systems water chemistry program applies

to both units.

The staff asked the applicant to discuss whether there have been any condition reports or

licensee event reports related to chemical excursions or component degradation occurring in

the systems within the scope of the auxiliary systems water chemistry control program. The

applicant responded that the operating experience discussed in its engineering report included

a review of condition reports, condition report trending data, and interviews with the applicant's

technical staff regarding plant system and program operating experience. The review did not

identify any condition reports or licensee event reports related to chemical excursions in the

systems covered under this program. Also, the condition report trending data did not identify

recurrent component degradation occurring in the systems covered under this program.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that auxiliary systems water chemistry control

program adequately manages the aging effects that have been observed at the applicant's

plant.

UFSAR Sucplement

In Appendix A, Section A.2.1.31, of the LRA, the applicant provided the UFSAR supplement for

the water chemistry control - auxiliary systems water chemistry control program and stated that

the program manages loss of material, cracking, and fouling, as applicable, of components in

the scope of license renewal. The program monitors and controls the relevant chemistry

conditions for components exposed to treated water environments.

During the audit, the staff noted that for the water chemistry related systems described in the

SRP-LR, Table 3.1-2 and Table 3.3-2, industry guidance and/or reports are identified. The staff

requested, in question B.1.30.1-6, that the applicant include in its LRA Section A.2.1.31 specific

industry guidance for the auxiliary water chemistry program similar to that in the SRP-LR,

Tables 3.1-2 and 3.3-2, or justify not including the industry guidance in this section

(RAI B.1.30.1-2).

In its response dated May 19, 2004, the applicant stated that a reference to industry guidance

used for the auxiliary systems water chemistry control program will be provided in LRA SAR

Section A.2.1.31 and committed to completing this action upon issuance of the renewed

license.

The staff asked the applicant to clarify what industry guidance would be referenced. In its

subsequent response to the staff's question, by letter dated July 22, 2004, the applicant stated

that the auxiliary water systems chemistry control program covers a variety of miscellaneous

systems and components using many different references such as EPRI reports, vendor

technical manuals, and other industry guidance. Applicable references can change frequently

3-88
based on industry experience or component replacements. Since the references change

frequently, the staff rescinded its request that the applicant revise the SAR Section A.2.1.31.

On the basis of its review of the applicant's response to the above question, the staff finds that

the applicant provides an adequate summary description of the program, as required by -

10 CFR 54.21(d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the ,CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

The NRC staff has reviewed LRA Appendix A, Section A.2.1, mAging Management Programs

and Activities" and Appendix B, Section B.0.3, 'ANO-2 Corrective Actions, Confirmation -;

Process and Administrative Controls," in accordance with the requirements of

10 CFR.54.21 (a)(3) and 10 CFR 54.21 (d). The staff has evaluated the adequacy of certain.,

aspects of the applicant's programs to manage the effects of aging. The particular aspects

.reviewed by the staff in this section encompass three quality assurance program attributes,

namely corrective actions, confirmation process, and administrative controls. These three

attributes of the quality assurance program are addressed for all of the applicant's AMPs.

The license renewal applicant is required to demonstrate that the effects of aging on structures

and components that are subject to an AMR will be adequately managed to ensure that their

intended functions will be maintained in a manner that is consistent with the CLB of the facility

throughout the period of extended operation. To manage these effects, applicants have :

developed new, or revised existing, AMPs and applied those programs to the SSCs of interest.,

For each of these AMPs, the existing 10 CFR Part 50, Appendix B, quality assurance program

may be used to address the attributes of corrective actions, confirmation process, and

administrative controls. - ,

3.0.4.1 Summary of Technical Information in Application

Appendix B, Section B.0.3, "ANO-2 Corrective Actions, Confirmation Process and

Administrative Controls," of the LRA provides the aging management activity description for

each activity credited for managing aging effects.,-.The applicant stated that it uses the existing

ANO-2, 10 CFR Part 50, Appendix B, quality, assurance program to address the elements of

corrective action, confirmation process, and administrative controls for all of its AMPs. The

applicant further states that these programs,-credited for license renewal, encompass both the

safety-related and non safety-related SSCsywithin the scope of license renewal.

t3-89
3.0.4.2 Staff Evaluation

During the audit of the applicant's renewal scoping and screening process, the staff also

examined the applicant's processes for addressing corrective action, confirmation processes,

and document control (the quality assurance attributes) associated with the various aging

management programs credited for managing the potential aging effects of SSCs over the

period of extended operation of the plant.

The audit team determined that the applicant had not described the AMP quality attributes in

Appendix A, "Updated Final Safety Analysis Report Supplement." Consistent with Branch

Technical Position IQMB-1, the applicant should either document a commitment to expand the

scope of its 10 CFR Part 50 Appendix B program to include nonsafety-related structures and

components subject to an AMP to address the AMP quality attributes during the period of

extended operation or propose an alternative means to address this issue. The staff requested

that the applicant clarify their commitments related to addressing the quality attributes of AMPs

applicable to nonsafety-related structures and components subject to aging management. The

description in Appendix A should provide sufficient information for the staff to determine if the

quality attributes for the Appendix A.1 aging management programs are consistent with the

review acceptance criteria contained in NUREG-1 800, Section A.2, "Quality Assurance for

Aging Management Programs (Branch Technical Position IOMB-1)." (This request for

information was documented as RAI 2.1-6).

The applicant responded by a letter to the NRC dated May 19, 2004. The following paragraph

will be added to Appendix A of the LRA. 'The Quality Assurance Program implements the

requirements of 1 OCFR50, Appendix B. The Quality Assurance Program includes the elements

of corrective action, confirmation process, and administrative controls and is applicable to all

aging management programs credited for license renewal including programs for safety-related

and non-safety related structures, systems and components."

The staff concluded that the applicant response had clarified their commitments related to

addressing the quality attributes of AMPs applicable to nonsafety-related structures and

components subject to aging management and had adequately addressed the questions

documented in RAI 2.1-6.

The audit team reviewed that the discussions of corrective actions contained in section B.0.3,

"Corrective Actions, Confirmation Process and Administrative Controls," of Appendix B, "Aging

Management Programs and Activities." The discussion stated that "in the case of significant

conditions adverse to quality... corrective action is taken to lessen the likelihood of recurrence."

This is not in agreement with the regulations contained in 10 CFR Part 50, Appendix B, section

XVI, "Corrective Actions," which states, in part, "in the case of significant conditions adverse to

quality, the measures shall assure that the cause of the condition is determined and corrective

actions taken to preclude repetition." The applicant was requested to address this discrepancy.

This request for information was documented as RAI 2.1-5.

The applicant responded by a letter to the NRC dated May 19, 2004, which stated that

Appendix B, Section B.0.3 under the heading of "Corrective Actions" would be clarified as

follows: 'in the case of significant conditions adverse to quality, measures are implemented to

ensure that the cause of the nonconformance is determined and that corrective action is taken

to preclude repetition."

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I

The staff concluded that the applicant's response had addressed the discrepancy between the

definition of corrective action contained in Appendix B of the LRA and 10 CFR Part 50 be

rewording that portion of Appendix B of the LRA to consistent with 10 CFR Part 50 and had

adequately responded to the questions documented in RAI 2.1-7.

3.0.4.3 Conclusion

The audit team did not observe any exceptions to the use of the site Appendix B quality

assurance program for the evaluation of the three quality assurance attributes. On the basis of

this review, the staff finds that the quality assurance attributes are consistent with 10 CFR

54.21 (a)(3). Therefore, the applicant's quality assurance attributes within the AMPs credited for

license renewal are acceptable.

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THIS PAGE IS INTENTIONALLY LEFT BLANK

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

This section of the SER documents the staff's review of the applicant's AMR results for the

reactor vessel, internals, and reactor coolant system components and component groups

associated with the following systems: - : -

* reactor vessel and control element drive mechanism

* reactor vessel internals

* Class 1 piping, valves, and reactor coolant pumps

* pressurizer' * steam generators r* ;

3.1.1 Summary of Technical Information In the Application

In LRA Section 3.1, the applicant provided AMR results for the reactor vessel, internals, and

reactor coolant system components and component groups. Table 3.1.1 of the LRA, "Summary

of Aging Management Programs for the Reactor Coolant System in Chapter IV of NUREG1801," provides a summary of the programs evaluated in the GALL Report for the RCS

component groups.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the reactor system components that are within the

scope of license renewal and subject to an AMR will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).-

The staff performed an audit 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 determine that the material presented in the LRA was*

applicable and that the applicant had identified the appropriate GALL AMPs. Section 3.0.3 of

this SER documents the staff's evaluations of the AMPs. The ANO-2 Audit and Review Report

documents the staff's audit findings, which are also summarized in Section 3.1.2.1 of this SER.;

The staff also audited and reviewed those AMRs that are consistent with the GALL Report and

for which further evaluation is recommended. The staff determined that the applicant's further

evaluations were consistent with the acceptance criteria in Section 3.1.3.2 of the SRP-LR.

Section 3.1.2.2 of the SER summarizes the staff's audit findings.

The staff conducted a technical review of the remaining AMRs that are not consistent with the

GALL Report. The 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. Section 3.1.2.3 of the SER summarizes the staff's review findings.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR Supplement to ensure

that they provide an adequate description of the programs credited with managing or monitoring

-aging for the reactor vessel, internals, and reactor coolant system components and component'

groups.

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Table 3.1-1 below provides 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 Ij

Component Group ' AgingEffectl AMP ln GALL *- t E alafon tA 

* - Mechanism." . RepAor-<tnf -, fx

Reactor coolant Cumulative fatigue TLAA, evaluated in TLAA-Metal Fatigue Consistent with

pressure boundary damage accordance with GALL, which

components 10 CFR 54.21(c)) recommends further

(Item Number evaluation (See

3.1.1-1) Section 3.1.2.2.1)

Steam generator Loss of material Inservice Inservice Inspection Consistent with

shell assembly due to pitting and inspection; water (B.1.14), Water GALL, which

(Item Number crevice corrosion chemistry Chemistry Control recommends further

3.1.1-2) (B.1.30) evaluation (See

Section 3.1.2.2.2)

Pressure vessel Loss of fracture TLAA, evaluated in TLAA-Reactor Consistent with

ferritic materials toughness due to accordance with Vessel GALL, which

that have a neutron neutron irradiation Appendix G of recommends further

fluence greater than embrittlement 10 CFR 50 and evaluation (See

1017 n/cm2 RG 1.99 Section 3.1.2.2.3)

(E>1 MeV)

(Item Number

3.1.1-4) .'

Reactor vessel Loss of fracture Reactor vessel Reactor Vessel Consistent with

beltline shell and toughness due to surveillance Integrity (B.1.21) GALL, which

welds neutron irradiation recommends further

(Item Number embrittlement evaluation (See

3.1.1-5) Section 3.1.2.2.3)

Westinghouse and Loss of fracture Plant specific Not Applicable to Consistent with

Babcock & Wilcox toughness due to ANO-2. Core GALL, which

(B&W) baffle/former neutron irradiation shroud plates are recommends further

bolts embrittlement and welded. evaluation (See

(Item Number void swelling Section 3.1.2.2.3)

3.1.1-6)

Small-bore reactor Crack initiation and Inservice Inservice Inspection Consistent with

coolant system and growth due to stress inspection; water (B.1.14), Water GALL, which

connected systems corrosion cracking chemistry; one-time Chemistry Control recommends further

piping (SCC), inspection (B.1.30) evaluation

(Item Number intergrangular (See Section

3.1.1-7) stress corrosion 3.1.2.2.4)

cracking (IGSCC),

and thermal and

mechanical loading

Vessel Shell Crack growth due to TLAA Not Applicable to Consistent with

(Item Number cyclic loading ANO-2 GALL, which

3.1.1-10) recommends further

evaluation (See

Section 3.1.2.2.5)

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Componet Group E iec AP in G L^gin -c- AMP in 'R ; -- Staff EvaIutionk

Me anism ' § e Hi' C - . 3 ,'- r - K

Reactor internals Changes in Plant specific RV Internal CASS Consistent with

(Item Number dimension due to (B.1.22), RVV - GALL, which

3.1.1-l1) void swelling ' Internals Stainless, recommends further

Steel (B.1.23) evaluation (See

Section 3.1.2.2.6)

PWR core support Crack initiation and Plant specific Water Chemistry Consistent wiith

pads, instrument growth due to SCC Control (6.1.30), GALL, which

tubes (bottom head and/or primary Alloy 600 Aging recommends further

penetrations), water stress Management evaluation (See pressurizer spray corrosion cracking (B.1.1), Inservice Section 3.1.2.2.7)

heads, and nozzles (PWSCC) Inspection (B.1.14) for the steam

generator

instruments and

drains

(Item Number

3.1.1-12) e ____| , * ; 

Cass austenitic Crack Initiation and Plant specific Water Chemistry Consistent with

stainless steel growth due to SCC Control (8.1.30), GALL, which

(CASS) reactor Inservice Inspection recommends further

coolant system (B.1.14) evaluation (See

piping -' . Section 3.1.2.2.7)

(Item Number

3.1.1-13) .

Pressurizer Crack initiation and Inservice Inservice Consistent with

instrumentation growth due to inspection; water Inspection(B.1.14), GALL, which

penetrations and PWSCC chemistry Alloy 600 (6.1.1), recommends further

heater sheaths and Water Chemistry evaluation (See

sleeves made of Ni- Control (B.1.30) Section 3.1.2.2.7) alloys

(Item Number

3.1.1-14) ' -_-_-_-_._-_,___

Westinghouse and' Crack initiation and Plant specific Not Applicable to Consistent with

B&W baffle former growth due to SCC . ANO-2 GALL, which

bolts ' - and Irradiation- recommends further

(Item Number assisted stress evaluation (See,

3.1.1-15) corrosion cracking Section 3.1.2.2.8)

(IASCC)

Westinghouse and Loss of preload due Plant specific Not Applicable to Consistent with.

B&W baffle former to stress relaxation ANO-2 - GALL, which

baffle bolts recommends further

(Item Number . evaluation

3.1.1-16) (See Section

3.1.2.2.9)

Steam generator Loss of section, Plant specific Not Applicable to Consistent with

feedwater thickness due to I ANO-2 GALL, which

impingement plate erosion . recommends further

and support . evaluation (See

(Item Number Section 3.1.2.2.10)

3.1.1-17) -

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0

Comup nent Groupt 1SAging Effect) AMP IrLA.,: taff Evaluauon

,'Me~charnlm R~Pn A

(Alloy 600) Steam Crack initiation and Steam generator Steam Generator Consistent with

generator tubes, growth due to tubing integrity; Integrity (B.1.25), GALL, which

repair sleeves, and PWSCC outside water chemistry Water Chemistry recommends further

plugs diameter stress Control (B.1.30) evaluation (See (Item Number corrosion cracking Section 3.1.2.2.11) 3.1.1-18) (ODSCC), and/or

intergranular attack

(IGA); or Loss of

material due to

wastage and pitting

corrosion, and

fretting and wear; or

deformation due to

corrosion at tube

support plate intersections

Tube support lattice Loss of section Plant specific Not Applicable to Consistent with

bars made of thickness due to ANO-2 GALL, which

carbon steel flow-accelerated recommends further

(Item Number corrosion (FAC) evaluation

3.1.1-19) (See Section

3.1.2.2.12)

Carbon steel tube Ligament cracking Plant specific Not Applicable to Consistent with

support plate due to corrosion ANO-2 GALL, which

(Item Number recommends further

3.1.1-20) evaluation (See

Section 3.1.2.2.13)

Steam generator Loss of material Combustion Not Applicable to Consistent with

feedwater inlet ring due to flow Engineering (CE) ANO-2 GALL, which

and supports accelerated steam generator recommends further

(Item Number corrosion feedwater ring evaluation (See

3.1.1-21) inspection Section 3.1.2.2.14)

Reactor vessel Crack initiation and Reactor head Inservice Inspection Consistent with

closure studs and growth due to SCC closure studs (B.1.14) GALL, which

stud assembly and/or IGSCC recommends no

(Item Number further evaluation

3.1.1-22) (See Section

3.1.2.1)

CASS pump casing Loss of fracture Inservice inspection Inservice Inspection Consistent with

and valve body toughness due to (B.1.14) GALL, which

(Item Number thermal aging recommends no

3.1.1-23) embrittlement further evaluation

(See Section

3.1.2.1)

CASS piping Loss if fracture Thermal aging Inservice Inspection Consistent with

(Item Number toughness due to embrittlement of (B.1.14) GALL, which

3.1.1-24) thermal aging CASS recommends no

embrittlement further evaluation

(See Section

3.1.2.1)

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Component Group; ;,- Aging Effectl. , ';>AP i GAL - .AMP In LRAuMechan sm "Rpot ; '- ion

BWR piping and Wall thinning due to Flow accelerated Flow-Accelerated Consistent with

fittings; steam flow accelerated corrosion Corrosion (B.1.11), GALL, which.

generator corrosion Water Chemistry recommends no

components Control (B.1.30) further evaluation

(Item Number (See Section

3.1.1-25) _ 3.1.2.1),

Reactor coolant Loss of material -Bolting integrity - Inservice Inspection Consistent with

pressure boundary due to wear, loss of (B.1.14), Bolting GALL, which

(RCPB) valve, preload due to and Torquing recommends no

closure bolting, stress relaxation; Activities (B.1.2) further evaluation

manway and crack initiation and (See Section

holding bolting, and growth due to cyclic 3.1.2.1)

closure bolting in loading and/or SCC

high-pressure and

high temperature

systems

(Item Number

3.1.1-26) .

CRD nozzle Crack initiation and Ni-alloy nozzles and Inservice Inspection; Consistent with

(Item Number growth due to penetrations; water (B.1.14), Water GALL, which

3.1.1-35) PWSCC chemistry Chemistry Control recommends no

(B.1.30), RV Head further evaluation

Penetrations (See Section

(B.1.20) 3.1.2.1)

Reactor vessel Crack initiation and Inservice Inservice Inspection Consistent with

nozzles safe ends growth due to cyclic inspection; water (B.1.14), Water - - GALL, which .-- -

and CRD housing; loading and/or SCC, chemistry Chemistry Control recommends no 7

reactor coolant and PWSCC (B.1.30). further evaluation

system components (See Section

(except CASS and 3.1.2.1); -

bolting)

(Item Number

3.1.1-36) - .

Reactor vessel Loss of fracture Thermal aging and RV Internal CASS Consistent with -

Internals CALL , toughness due to neutron irradiation (B.1.22) GALL, which

components thermal aging, embrittlement -. recommends no

(Item Number neutron irradiation ;* further evaluation

3.1.1-37) embrittlement and (See Section

void swelling 3.1.2.1)

External surfaces of Loss of material Boric acid corrosion Boron Acid i Consistent with

carbon steel due to boric acid _ Corrosion - GALL, which* - -

components in corrosion : -- - Prevention (B.1.3) recommends no.-

reactor coolant , further evaluation'

system pressure (See Section

boundary 3.1.2.1)

(Item Number

3.1.1-38) _

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Component Group Aging Effec ; AMP in GALL, * AMP in ERAS St-ff alua to

Mechanism s >-'- Re ort- ;;:. ; -v- a- l. 

Steam generator Loss of material Inservice inspection Not Applicable to Consistent with'

secondary due to erosion ANO-2 GALL, which

manways and recommends no

handholds (carbon further evaluation

steel) (See Section

(Item Number 3.1.2.3.5)

3.1.1-39)

Reactor internals, Loss of material Inservice inspection Inservice Inspection Consistent with

reactor vessel due to wear (B.1.14) GALL, which

closure studs, and recommends no

core support pad further evaluation

(Item Number (See Section

3.1.1-40) 3.1.2.1)

Pressurizer integral Crack initiation and Inservice inspection Inservice Inspection Consistent with

support growth due to cyclic (B.1.14) GALL, which

(Item Number loading recommends no

3.1.1-41) further evaluation

(See Section

3.1.2.1)

Upper and lower Loss of preload due Inservice RV Internals SS Consistent with

internals assembly to stress relaxation inspection; loose (B.1.23), Inservice GALL, which

(Westinghouse) part and/or neutron Inspection (B.1.14) recommends no

(Item Number noise monitoring further evaluation

3.1.1-42) (See Section

3.1.2.1)

Reactor vessel Loss of fracture PWR vessel RV Internals SS Consistent with

internals in fuel toughness due to internals; water (B.1.23) GALL, which

zone region (except neutron irradiation chemistry recommends no

Westinghouse and embrittlement and further evaluation

B&W baffle former void swelling (See Section

bolts) 3.1.2.1)

(Item Number

3.1.1-43)

Steam generator Crack initiation and Inservice Water Chemistry Consistent with

upper and lower growth due to SCC, inspection; water Control (B.1.30). GALL, which

heads, tubesheets, PWSCC, and or chemistry Alloy 600 (B.1.1), recommends no

and primary nozzles IASCC Inservice Inspection further evaluation

and safe ends (B.1.14) (See Section

(Item Number 3.1.2.1)

3.1.1-44)

Vessel Internals Loss of fracture PWR vessel RV Internals CASS Consistent with

(except toughness due to internals; water (B.1.23), RV GALL, which

Westinghouse and neutron irradiation chemistry Internals Stainless recommends no

B&W baffle former embrittlement and Steel (B.1.23), further evaluation

bolts) void swelling Water Chemistry (See Section

(Item Number Control (B.1.30), 3.1.2.1)

3.1.1-45) Inservice Inspection

(B.1.14)

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Copnn rup" r~Ag ng fetS ~ $A~nGL-L.' -AMP In I-RA'" - Staff Evaluatl~n *6~m-po-n-e~nt'Gro1 Efe~1-, n A L - '- o' 

Reactor internals Loss of preload due Inservice Not Applicable to Consistent with

(B&W screws and to stress relaxation inspection; loose ANO-2 GALL, which

bolts) part monitoring ' recommends no

(Item Number further evaluation

3.1.1-46) (See Section

3.1.2.1) , X

Reactor vessel Loss of material Reactor head Inservice Inspection Consistent with

closure studs and due to wear closure studs (B.1.14) - GALL, which

stud assembly - , . I,, - recommends no

(Item Number further evaluation

3.1.1-47) (See Section

; _ '_ 3.1.2.1)

Reactor intemals Loss of preload due Inservice RV Internals - Consistent with

(Westinghouse to stress relaxation inspection; loose Stainless Steel GALL, which,

upper and lower part monitoring (B.1.23), Inservice recommends no

internal assemblies, , ' Inspection (B.1.14) further evaluation -

CE bolts and tie (See Section

rods) 3.1.2.1)

(Item Number

3.1.1-48) I

The staff's review of the ANO-2 RCS and associated components followed one of several

approaches. One approach, documented in Section 3.1.2.1 of this SER, involves the staff's

audit and review of the AMR results for components in the RCS that the applicant indicated are

consistent with the GALL Report and do not require further evaluation. Another approach,

documented in Section 3.1.2.2 of this SER, involves the staff's audit and review of the AMR

results for componients' in the RCS that the applicant indicated are consistent with the GALL'

Report and for which further evaluation is recommended. A third approach, documented in

Section 3.1.2.3 of this SER, involves the staff's technical review of the AMR results for

components in the RCS that the applicant indicated are not consistent with the GALL Report or

are not addressed in the GALL Report. Section 3.0.3 of this SER documents the staff's review

of AMPs that are'credited to manage or monitor aging effects of the RCS.

3.1.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the ApDlication

In Section'3.1.2.1 of the' LRA, the applicant identified the materials, environments, and aging

effects' requiring management. The applicant identified the following programs that manage the

aging effects related to the reactor vessel, iritermnls, RCS, pressurizer, and SG components"'

* Reactor Vessel Integrity Program

* . Inservice Inspection Program -

Water Chemistry Control Program . i'

* Boric Acid Corrosion'Pievention Program

* Alloy 600 Aging Management Program

* Reactor Vessel Head Penetration Program

* Bolting and Torquing Activities Program

s 3-99
* Reactor Vessel Internals Cast Austenitic Stainless Steel Components Program

* Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program

* Cast Austenitic Stainless Steel Evaluation Program

* Pressurizer Examinations Program

* Steam Generator Integrity Program

* Flow-Accelerated Corrosion Program

Staff Evaluation

In Tables 3.1.2-1 through 3.1.2-5 of the LRA, the applicant provided a summary of AMRs for

the reactor vessel, internals, RCS, pressurizer, and SGs, and identified which AMRs it

considered to be consistent with the GALL Report.

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 are bounded by the GALL

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

identified by 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 determine 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 determine consistency

with the GALL Report. The staff determined that it reviewed and accepted the identified

exceptions to the GALL AMPs. 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 is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item is different, but 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 could not

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 under review. The staff audited these line items to

determine consistency with the GALL Report. The staff also determined whether the AMR line

item of the different component applies to the component under review and whether the AMR is

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item is different, but consistent with the

GALL Report for material, environment, and aging effect. In addition, the AMP takes some

3-100
exceptions to the AMP identified in the GALL Report. The staff audited these line items to

determine consistency with the GALL Report. The staff determined whether the AMR line item

of the different component applies to the component under review. The staff determined that itreviewed and accepted the identified exceptions to the GALL AMPs. 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 is 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 determine consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA and program

bases documents, which are available at the applicant's engineering office. On the basis of its

audit and review, the staff finds that the AMR results, which the applicant claimed t6 be

consistent with the GALL Report, are in fact consistent with the AMRs in the GALL Report.

Therefore, the staff finds that the applicant identified applicable aging effects that are

appropriate for the combination of materials and environments listed.

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the component intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Conclusion

The staff has evaluated the applicant's claim of consistency with the GALL Report. The staff

also has reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review,

the staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are in fact consistent with the'AMRs in the GALL Report. Therefore, the staff finds that

the applicant has demonstrated that the effects of aging for these components can be

adequately managed so that their intended functions can be maintained consistent with 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 ADDlication

In Section 3.1.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for reactor vessel, internals, and RCS components. The

applicant provided information concerning how it will manage the following aging effects:

; . - .. 4:. . .

* cumulative fatigue damage .

* loss of material from pitting and crevice corrosion

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U

* loss of fracture toughness as a resulting of neutron irradiation embrittlement

* crack initiation and growth caused by thermal and mechanical loading or SCC

* crack growth resulting from cyclic loading

* changes in dimension caused by void swelling

* crack initiation and growth resulting from SCC or PWSCC

* crack initiation and growth resulting from SCC or IASCC

* loss of preload caused by stress relaxation

* loss of section thickness as a result of erosion

* crack initiation and growth from PWSCC, ODSCC, or IGA or loss of material resulting

from wastage and pitting corrosion or loss of section thickness caused by fretting and

wear or denting from corrosion of carbon steel tube support plate

* loss of section thickness caused by flow-accelerated corrosion

* ligament cracking resulting from corrosion

* loss of material caused by flow-accelerated corrosion

* quality assurance 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 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 Section 3.1.2.2 of the SRP-LR. The ANO-2

ANO-2 Audit and Review Report documents the details of the staff's onsite audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections of this SER.

3.1.2.2.1 Cumulative Fatigue Damage

As stated in the SRP-LR, fatigue is a TLAA, as defined in 10 CFR 54.3. TLAAs must be

evaluated in accordance with 10 CFR 54.21 (c)(1). Section 4.3 of this SER documents the

staff's review of the applicant's evaluation of this TLAA. In performing this review, the staff

followed the guidance in Section 4.3 of the SRP-LR.

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3.1.2.2.2 Loss of Material from Pitting and Crevice Corrosion

In Section 3.1.2.2.2 of the LRA, the applicant addressed loss of material of SG assemblies due

to pitting and crevice corrosion. U'.

*,, ,' ! 1t^j - '

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion could,

occur in the SG shell assembly. The existing program relies on control of water chemistry to;

mitigate corrosion and ISI to detect loss of material.' NRC IN 90-04, "Cracking of the Upper

Shell-to-Transition Cone Girth Welds in Steam Generators,' states that if general corrosion

pitting of the shell exists, the existing program may not be sufficient. In that case, the GALL

Report recommends augmented inspections to manage the aging effect. , . . .. . .- . . 1} 

The AMPs recommended by the GALL Report for managing the aging of SG assemblies due to

pitting and crevice corrosion are ASME Section Xl inservice inspection, Subsections IWB, IWC,

and IWD (XI.M1) program to detect loss of material and the water chemistry (XI.M2) program to

mitigate corrosion. The GALL Report recommends a plant-specific program to conduct

augmented inspections. ..

The applicant credited the inservice inspection program (AMP B.1.14) and the primary and

secondary water chemistry control program (AMP B.1.30.3) for managing loss of material due

to pitting and crevice corrosion on the internal surfaces of the SG shell. The staff reviewed the

inservice inspection program and the primary and secondary water chemistry control program

and its evaluation of these programs is documented in Sections 3.0.3.3.5 and 3.0.3.1 of this

SER, respectively. - ,,

The staff reviewed IN 90-04, which identifies the need to augment inspections beyond the

requirements of ASME Section Xi if general corrosion pitting of the SG shell is known to exist in

order to differentiate isolated cracks from inherent geometric conditions. The applicant

replaced its SGs in 2000. The staff reviewed operating experience which indicated that no

pitting corrosion of the SG shell has been detected to date, and that water chemistry has been

maintained for these new SGs per EPRI guidelines. The staff finds that the augmented

inspections recommended by NRC IN 90-04, as referenced in the SRP-LR, do not currently

apply to the the applicant's SGs.-

Since pitting corrosion has not been detected on the SG shell since installation, the staff finds

that augmented inspections are not required and that the current water chemistry control and

inservice inspection programs are adequate to manage aging.

The staff finds that the applicant has demonstrated that the effect of aging for loss of material

due to pitting and crevice corrosion will be adequately.managed so that the intended functions

will be maintained consistent with the CLB during the period of extended operation.

: ed ;. . .-

3.1.2.2.3 Loss of Fracture Toughness from Neutron Irradiation Embrittlement

In Section 3.1.2.2.3 of the LRA, the applicant addressed (1) loss of fracture toughness due to

neutron irradiation embrittlement of the reactor.vessel (RV) beltline materials, as managed.

using both a plant-specific AMP and the TLAAs on neutron irradiation embrittlement, and (2)

loss of fracture toughness of RV internal components as a result of neutron irradiation

embrittlement and void swelling.

3-1 03
a

Section 3.1.2.2.3 of the SRP-LR states that neutron irradiation embrittlement of RV beltline

materials (i.e., with neutron fluences greater than 1.0x1 017 n/cm2 [E 2 1.0 MeV]) are to be

treated as TLAAs, as defined in 10 CFR 54.3. Section 3.1.2.2.3 of the SRP-LR also states that

loss of fracture toughness due to neutron irradiation embrittlement of the RV beltline materials

is to be managed using a plant-specific AMP. In this case the plant-specific AMP is required to

be the RV materials surveillance program that is mandated by 10 CFR Part 50, Appendix H.

These RV materials surveillance programs monitor for neutron irradiation embrittlement by

testing irradiated material test specimens that are representative of the materials located in the

beltline region of the RV.

The plant-specific AMP recommended by the GALL Report for managing loss of fracture

toughness/neutron irradiation embrittlement of the RV beltline materials is AMP XI.M31,

"Reactor Vessel Surveillance," which complies with the requirements of 10 CFR Part 50,

Appendices G and H, and 10 CFR Part 50.61.

The applicant stated that loss of fracture toughness due to neutron irradiation embrittlement of

the ferritic RV materials meets the definition of a TLAA, as defined in 10 CFR 54.3. The

applicant stated that this TLAA is described in Section 4.2 of the LRA. The staff evaluates the

TLAA on neutron irradiation embrittlement in Section 4.2 of this SER.

The applicant stated in the LRA that loss of fracture toughness due to irradiation embrittlement

of the reactor vessel beltline materials is managed by the Reactor Vessel Integrity Program

(AMP B.1.21). This program is a plant-specific material surveillance program which monitors

the effect of operational fluence levels on material test specimens that are contained in

surveillance capsules positioned within the RV cavity. These surveillance capsule test

specimens are representative of materials with the beltline region of the RV and are irradiated

during power operations. These surveillance capsules are periodically withdrawn and the

specimens within the capsules are tested and analyzed for fracture toughness and other

material properties. The staff's evaluation of the Reactor Vessel Integrity Program is

documented in Section 3.0.3.2.6 of this SER.

SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron irradiation

embrittlement and void swelling could occur in Westinghouse and B&W baffle/former bolts.

Section IV.B3 of GALL, Volume 2, identifies additional RV internal components that may be

subject to loss of fracture toughness due to irradiation embrittlement and/or void swelling.

The applicant stated that this item is not applicable to ANO-2 because ANO-2 reactor vessel

internals do not include baffle/former bolts. This does not address the potential for loss of

fracture toughness due to neutron irradiation embrittlement and void swelling to occur in other

RV internal components, as itemized in particular AMR line items in Section IV.B3 of GALL,

Volume 2. The applicant, however, is participating in the EPRI MRP's industry initiative studies

on RV internal components and has, as part of its Reactor Vessel Internals Program,

committed to submit its program description for the ANO-2 RV internals, including the

inspection plan, to the staff for review and approval. This commitment will address aging

management of void swelling and neutron irradiation embrittement of the RV internal

components. The staff evaluation of the Reactor Vessel Internals Program is given in Section

3.0.3.1 of this SER.

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3.1.2.2.4 Crack Initiation and Growth from Thermal and Mechanical Loading or StressCorrosion Cracking '

In Section 3.1.2.2.4 of the LRA, the applicant addressed the potential crack initiation and

growth due to thermal and mechanical loading or stress corrosion cracking (SCC) (including

intergranular SCC) 'that could occur in small-bore' RCS and connected system piping less than

4-inch'nominal pipe size (NPS 4). - -

Section 3.1.2.2.4 of the SRP-LR states that the GALL Report recommends that a plant-specific

destructive examination or a nondestructive exa'mination (NDE) that permits inspection of the

inside surfaces of the piping be conducted t6o ensure that cracking has not occurred and the

component intended function will be maintained during the period of extended'operation. The

applicant should assess service-induced weld cracking is not occurring in small-bore piping less

than NPS 4. A one-time inspection of a sample of locations is an acceptable method to ensure

that the aging effect is not occurring and the component's intended function will be maintained

during the period of extended operation. Per ASME Section Xl, 1995 Edition, Examination

'Category B-J or B-F, small bore piping, defined as piping less tharn NPS 4, does not receive

volumetric inspection.

The AMPs recommended by the GALL Report are XI.M1, "ASME Section Xl Inservice - Inspection, Subsections IWB, IWC, and IWD," to detect loss of material and XI.M2, 'Water

Chemistry," to mitigate SCC. The GALL Report recommends GALL AMP XI.M32, 'One-Time

lnspection," as an acceptable verification method to ensure that cracking is not occurring in

small bore piping.

The applicant credited the inservice inspection program (AMP B.1.14) and the primary and

secondary water chemistry control program (AMP B.1.30.3) to mitigate cracking of reactor

coolant piping. The staff's review of these programs is documented in Sections 3.0.3.3.5 and

3.0.3.1 of this SER, respectively.

To address the GALL Report recommendation of a plant-specific destructive examination or an

NDE for inspection of inside surfaces of small bore piping, the applicant stated, in LRA Section

3.1.2.2.4 and Table 3.1.1-7, that it has implemented a risk-informed methodology at ANO-2 to

select, for small bore RCS and connected systems piping, RCS piping welds for inspection.

The applicant stated, in LRA Section 3.1.2.2.4, that the current inspection methods as

described in the inservice inspection program appropriately address cracking of small bore

piping systems less than four inch nominal pipe schedule (NPS 4) and greater than i-inch

(NPS 1). The staff finds that this methodology appropriately addresses cracking of small bore

piping greater than NPS 1, and the risk-informed methodology adequately manages cracking

initiation and growth aging mechanisms'duing'the-period of extended operation. {:

In Section 3.1.2.2.4 of the LRA, the applicant Stated that, for NPS 1 RCS piping and smaller,

the'piping is austenitic stainless steel and is not within the scope of the risk-informed selection

of piping welds for inspection. The applicant further stated that volumetric examinations of NPS

1 RCS piping and smaller are not effective, and the applicant performs system leakage testing,

in accordance with ASME Section XI, as the preferred alternative to inspection of the inside

surfaces of small bore piping NPS-1 and smaller.

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W

In discussions with the applicant, the staff asked the applicant to clarify how the alternative of

system leakage testing for NPS 1 RCS piping and smaller will adequately manage aging of

small bore piping and to provide the technical basis for not including piping NPS 1 and smaller

in the sample inspections from the risk-informed selections.

In its response, the applicant stated that operating experience has confirmed that leakage from

NPS 1 and smaller piping is readily detected and corrected prior to loss of system function.

Additionally, the applicant stated that it had implemented a program to investigate the potential

for cracking of welded joints in RCS piping less than or equal to NPS 1 since the discovery of a

cracked weld in an ANO-1 RCS drain line in 1989. Additionally, the applicant stated that the

risk (based on probability and consequences) of failure of the 1-inch and smaller piping is less

than the risk of failures of locations selected for inspection in the small-bore piping inspection

program.

On the basis of the applicant's response and its review, the staff finds that visual inspection of

NPS 1 and smaller RCS piping using systems leakage testing, in conjunction with volumetric

examinations of NPS 1 to NPS 4 RCS piping of the same material and environment, adequately

manages the effects of crack initiation and growth due to thermal and mechanical loading or

stress corrosion cracking prior to loss of intended function. This approach is consistent with

that for ANO-1 which was evaluated and approved by the staff in NUREG-1 743, "Safety

Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 1.

The staff finds that the applicant has demonstrated that crack initiation and growth due to

thermal and mechanical loading or SCC on small-bore RCS and connected systems piping will

be adequately managed so that the intended functions will be maintained consistent with the

CLB during the period of extended operation.

3.1.2.2.5 Crack Growth from Cyclic Loading

As stated in the SRP-LR, 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). The staff's

review of the applicant's evaluation of this TLAA is documented in Section 4.3 of this SER. In

performing this review, the staff followed the guidance in Section 4.3 of the SRP-LR.

3.1.2.2.6 Changes in Dimension from Void Swelling

In Section 3.1.2.2.6 of the LRA, the applicant addressed changes in dimension due to void

swelling that could occur in reactor internal components.

Section 3.1.2.2.6 of the SRP-LR states that the GALL Report recommends that changes in

dimension due to void swelling in reactor internal components be evaluated to ensure that this

aging effect is adequately managed. The GALL Report recommends that a plant-specific

AMP be evaluated to manage the effects of changes in dimension due to void swelling and the

loss of fracture toughness associated with swelling.

The applicant stated that the void swelling of reactor vessel internals is managed by the reactor

vessel internals cast austenitic stainless steel (CASS) program (AMP B.1.22) and the reactor

vessel internals stainless steel plates, welds, forgings, and bolting program (AMP B.1.23) using

supplemental examinations or component-specific evaluations. The applicant has committed to

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further understanding of this aging effect through industry programs to provide additional bases

for supplemental examinations or component-specific evaluations.

The staff evaluated the reactor vessel internals CASS program and the reactor vessel internals

stainless steel plates, welds, forgings; and bolting program. The staff documented its results in

Section 3.0.3.1 of this SER. These programs will be consistent with GALL AMPs XI.M13,

"Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

(CASS)," and Xl.M1 6, "PWR Vessel Internals," respectively. -

The staff finds the applicant's approach for managing changes in dimension due to void

swelling reasonable because the approach will be based on the guidelines developed by the

ongoing industry activities related to void swelling. The applicant has committed to submitting

both AMPs B.1.22 and B.1.23 to the staff for review and approval 24 months prior to the period,

of extended operation. To obtain NRC staff approval of its proposed inspection plans regarding

CASS components and Reactor Vessel Internals prior to entering the period of extended

operation for ANO-2, the applicant must submit a license amendment request. ,After the NRC -

staff's approval of the inspection plan, and future changes to the inspection plan will be

evaluated in accordance with 10 CFR 50.59. :

3.1.2.2.7 Crack Initiation and Growth from Stress-Corrosion Cracking or Primary Water StressCorrosion Cracking

The staff reviewed Section 3.1.2.2.7 of the LRA against the criteria in SRP-LR Section

3.1.2.2.7, which recommends plant-specific programs to address these aging mechanisms.

In Section 3.1.2.2.7 of the LRA, the applicant addressed (1) crack initiation and growth due to

SCC and primary water stress corrosion cracking (PWSCC) in the surge nozzle thermal sleeve,

safety injection nozzle thermal sleeve, charging inlet nozzle thermal sleeve, resistance

temperature detector nozzles, pressure measurement nozzle, sampling nozzle, and partial

nozzle replacement. Reactor vessel items included in this grouping are the lower shell and

bottom head cladding, surveillance capsule holders, core stabilizing lugs, core stop and support

lugs, and the flow baffle and skirt. Steam generator items included in this grouping are the tube

plate cladding, channel head divider plate, and primary nozzle closure rings; (2) crack initiation

and growth due to SCC in the pressurizer surge line piping and fittings fabricated of CASS; and

(3) crack initiation and growth due to PWSCC in'nickel-based alloy material such as the.

pressurizer instrumentation nozzles, heater sheaths and sleeves, and thermal sleeves. ANO-2

pressurizer components included in this grouping are the instrument nozzles, X-1 and T-4

heater penetration nozzles and plugs, original heater sheath, heater sleeve, and end plugs.

Section 3.1.2.2.7 of the SRP-LR states that',-.

Crack initiation and growth due to SCC and PWSCC could occur in core support

pads (or core guide lugs), instrument tubes (bottom head penetrations), pressurizer

spray heads, and nozzles for the SG instruments and drains. The GALL Report

recommends further evaluation to ensure that these aging effects are adequately

managed. The GALL Report recommends that a plant-specific AMP be evaluated

because existing programs may not be capable of mitigating or detecting crack

initiation and growth due to SCC.

3-1 07
Crack initiation and growth due to SCC could occur in CASS RCS piping and fittings

and pressurizer surge line nozzle. The GALL Report recommends further evaluation

of piping that does not meet either the reactor water chemistry guidelines of

TR-105714 or material guidelines of NUREG-0313.

* Crack initiation and growth due to PWSCC could occur in pressurizer instrumentation

penetrations and heater sheaths and sleeves made of nickel alloys. The existing

program relies on ASME Section Xl ISI and on control of water chemistry to mitigate

PWSCC. However, the existing program should be augmented to manage the

effects of SCC on the intended function of nickel-alloy components. The GALL

Report recommends that the applicant provide a plant-specific AMP or participate in

industry programs to determine appropriate AMPs for PWSCC of the Alloy 182 weld.

The applicant credited the following plant-specific programs for each of the three SRP-LR

criteria:

* Cracking of nickel-based alloy components due to PWSCC is managed by the Alloy

600 aging management program (AMP B.1.1) supplemented by the water chemistry

control program and the inservice inspection program. Additionally, EPRI, through its

material reliability program (MRP) and in conjunction with the PWR owners groups, is

developing a strategic plan to manage and mitigate cracking of nickel-based alloy

items. The applicant has stated that the guidance developed by the MRP will be

used to identify critical locations for inspection and to augment existing ISI

inspections, as appropriate. Since RCS pressure control using the pressurizer sprays

is not an intended function of the pressurizer, the pressurizer spray assembly is not

subject to aging management for ANO-2.

* Crack initiation and growth due to SCC at welded connections, including the

pressurizer surge line and fittings, is managed by the water chemistry control

program and the inservice inspection program.

* The programs credited for the management of PWSCC of these nickel-based alloy

items are the Alloy 600 aging management program and the water chemistry control

program, supplemented by the inservice inspection program. As described in Item 1

above, the applicant committed to participation in the Alloy 600 industry programs to

identify critical locations for inspection and augment existing ISI, where appropriate.

The staff reviewed the plant-specific programs for these aging effects as follows:

* The staff's evaluation of the primary and secondary water chemistry control program

(AMP B13.30.3) is documented in Section 3.0.3.1 of this SER.

* The staff's evaluation of the inservice inspection program (AMP B.1.14) is

documented in Section 3.0.3.3.5 of this SER.

The staff's evaluation of the Alloy 600 aging management program (AMP B.1.1) is documented

in Section 3.0.3.3.1 of this SER.

The staff finds that the applicant appropriately evaluated AMR results which address these

aging mechanisms, as recommended in the GALL Report.

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On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of crack initiation and growth due to SCC or PWSCC, as recommended

in the GALL Report.

3.1.2.2.8 Crack Initiation and Growth from Stress-Corrosion Cracking or Irradiation-Assisted

Stress-Corrosion Cracking

In Section 3.1.2.2.8 of the LRA, the applicant stated that its reactor vessel internals do not

include baffle/former bolts. The core shroud plates'are joined in a welded configuration and

that the discussion in this paragraph of NUREG-1800 is not applicable.

On the basis that the baffle/former bolts are not part of the design of reactor vessel internals,

the staff finds that this aging effect is not applicable.

3.1.2.2.9 Loss of Preload from Stress Relaxation

In Section 3.1.2.2.9 of the LRA, the applicant stated that its reactor vessel internals do not

include baffle/former bolts. The core shroud plates are joined in a welded configuration and

that the discussion in this paragraph of NUREG-1 800 is not applicable.-

On the basis that the baffle/former bolts are not part of the design of reactor vessel internals,

the staff finds that this aging effect is not applicable.

3.1.2.2.10 Loss of Section Thickness from Erosion

In Section 3.1.2.2.10 of the LRA, the applicant stated that its steam generators do not include

impingement plates and that the discussion in this'paragraph is not applicable.

Section 3.1.2.2.10 of the SRP-LR states that loss of section thickness due to erosion could.,

occur in SG feedwater impingement plates and supports. The GALL Report recommends

further evaluation of a plant-specific AMP to ensure that this aging effect is adequately

managed.

On the basis that impingement plates are not part of the steam generator design, the staff finds

that this aging effect is not applicable.

3.1.2.2.11 Crack Initiation and Growth from Primary Water Stress-Corrosion Cracking,

Outside-Diameter Stress-Corrosion Cracking, or Intergranular Attack orLoss of

-Material from Wastage and Pitting Corrosion, or Loss of Section-Thickness from

Fretting and Wear, or Denting from Corrosion of Carbon Steel Tube Support Plate

In Section 3.1.2.2.11 of the LRA, the applicant addressed crack initiation and growth due to -- PWSCC, outside diameter SCC (ODSCC,) or intergranular attack (IGA) or loss of material due

to wastage and pitting corrosion or deformation due to corrosion that could occur in

nickel-based alloy components of the SG tubes and plugs.

Section 3.1.2.11 of the SRP-LR states that crack initiation and growth due to PWSCC, ODSCC,

or IGA or loss of material due to wastage and pitting corrosion or deformation due to corrosion

could occur in Alloy 600 components of the SG tubes, repair sleeves and plugs. All PWR

3-1 09
licensees have committed voluntarily to a SG degradation management program described in

NEI 97-06; these guidelines are currently under NRC staff review. The GALL Report

recommends that an AMP based on the recommendations of staff-approved NEI 97-06

guidelines, or other alternate regulatory basis for SG degradation management, should be

developed to ensure that this aging effect is adequately managed.

The SRP-LR also states that crack initiation and growth due to PWSCC, ODSCC or IGA or loss

of material due to wastage and pitting corrosion or deformation due to corrosion could occur in

nickel-based alloy components of the SG tubes and plugs.

To manage the effects of aging, the applicant credited the SG integrity program (AMP B.1.25)

supplemented by the primary and secondary water chemistry control program (AMP B.1.30.3)

and the inservice inspection program (AMP B.1.14).

The staff's evaluation of the SG integrity program is documented in Section 3.0.3.1 of this SER.

The staff evaluated the primary and secondary water chemistry control and the inservice

inspection program and its evaluations are documented in Sections 3.0.3.1 and 3.0.3.3.5 of this

SER, respectively. For general and pitting corrosion and for the assessment of tube integrity

and plugging or repair criteria of flawed tubes, the SG integrity program acceptance criteria are

in accordance with NEI 97-06 guidelines.

On the basis of its review of the primary and secondary water chemistry control program and

the inservice inspection program, the staff finds that the applicant appropriately evaluated AMR

results involving plant-specific programs to address these aging mechanisms, as recommended

in the GALL Report.

3.1.2.2.12 Loss of Section Thickness from Flow-Accelerated Corrosion

In Section 3.1.2.2.12 of the LRA, the applicant states that its steam generators do not include

carbon steel tube support lattice bars. Therefore, loss of section thickness of these bars is not

an applicable aging effect.

On the basis that carbon steel tube support lattice bars are not part of the SG design, the staff

finds that this aging effect is not applicable.

3.1.2.2.13 Ligament Cracking from Corrosion

In Section 3.1.2.2.13 of the LRA, the applicant states that the steam generators have stainless

steel tube support plates. Therefore, ligament cracking due to corrosion is not an applicable

aging effect.

On the basis that carbon steel components are not part of the SG tube support plate design,

the staff finds that this aging effect is not applicable to ANO-2.

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3.1.2.2.14 Loss of Material from Flow-Accelerated Corrosion

In Section 3.1.2.2.14 of the LRA, the applicant stated that the discussion in this paragraph of

NUREG-1 800 is applicable to CE System 80 steam generators only, whereas it has

Westinghouse Delta 109 steam generators.

On the basis that CE System 80 SGs are not part of the ANO-2 SGs design, the staff finds that

ANO-2 components are not subject to this aging effect and that this aging effect is not

applicable'to ANO-2.

3.1.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

Section 3.0.4 of this SER provides a separate evaluation of the applicant's Quality Assurance

Program.

Conclusion

On the basis of its review of component groups evaluated in the GALL Report for which the

applicant has claimed consistency with GALL, and for which the GALL Report recommends

further evaluation, the staff concludes that the applicant has adequately addressed the issues

that were further evaluated. In addition, the'staff reviewed the applicant's additional evaluations

against the criteria contained in Section 3.1.2.2 of the SRP-LR. Because the applicant's AMR

results are otherwise consistent with the GALL Report, the staff finds that the applicant has

demonstrated that the effects of aging can be adequately managed so that the component

intended functions can 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 ApDlication

In Tables 3.1.2-1 through 3.1.2-5 of the LRA, the applicant indicated, by means of notes F

through J, that neither the identified component nor the material and environment combination

is evaluated in the GALL Report. Thus, the applicant provided information concerning how the

aging effect will be managed. LRA Tables 3.1.2-1 through 3.1.2-5 use the following notes to

indicate the status of a specific component, environment, material, and/or aging effect in the

GALL Report:

* Note F indicates that the material is not in the GALL Report for the identified

component.

* Note G indicates that the environment is not in the GALL Report for the identified

component and material.

Note H indicates that the aging effect is not in the GALL Report for the identified

component, material, and environment combination.

* Note I indicates that the aging effect in the GALL Report for the identified component,

material, and environment combination is not applicable

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Note J indicates that the GALL Report does not evaluate either the identified component

or the material and environment combination.

Staff Evaluation

For component type and material and environment combinations that are not evaluated in the

GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant

had demonstrated that the effects of aging will be adequately managed so that the component

intended functions will be maintained consistent with the CLB during the period of extended

operation.

The following sections discuss the staff's evaluation.

3.1.2.3.1 Reactor Vessel and Control Element Drive Mechanism Pressure Boundary

Summary of Technical Information in the Application

In Section 3.1.2.1.1 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects for the reactor vessel (RV) and control element drive mechanism (CEDM) and

associated pressure boundary components:

* Reactor Vessel Integrity Program

* Inservice Inspection Program

* Water Chemistry Control Program

* Boric Acid Corrosion Prevention Program

* Alloy 600 Aging Management Program

* Reactor Vessel Head Penetration Program

* Bolting and Torquing Activities Program

Table 2.3.1-1 of the LRA lists the following individual system components within the scope of

license renewal and subject to an AMR:

* closure head lifting lugs

* closure studs, nuts, and washers

* core stabilizing lugs

* core stop lugs

* flow skirt

* grayloc clamp

* grayloc clamp studs

* grayloc clamp nuts

* in-core instrumentation drive nuts

* in-core instrumentation spacer sleeves

* reactor vessel support pads

* shear lugs

* surveillance capsule holders

* CEDM motor housing

* CEDM upper pressure housing

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0

0

0

S

00

S

0

S

0

0

0

CEDM ball seal housing

CEDM upper pressure housing upper fitting

CEDM motor housing upper and lower end fittings

CEDM upper pressure housing lowerifitting

CEDM nozzle

in-core instrumentation nozzle tubes:

-CEDM steel ball

in-core instrumentation flange adapter/seal plate

reactor vessel vent pipe

reactor vessel vent pipe flange

bottom head (torus and dome)

upper shell

closure head dome (torus and dome)

-closure head flange

intermediate shell

lower shell

primary inlet nozzles

primary outlet nozzles

primary inlet nozzle safe ends "I;

primary outlet nozzle safe ends

. . I

vessel flange ' - -I

In Table 3.1.2-1 of the LRA, the applicant provided a summary of AMRs for the RV and CEDM

and associated pressure boundary components and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation ;

The staff reviewed Table 3.1.2-1 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the RV and CEDM pressure boundary component groups.

Aging Effects --

Aging Management of Low-Alloy Steel RV Components In External Air Environments. The

applicant identified that low-alloy steel components that are exposed to an external air

environment are subject to cracking, cracking (fatigue), loss of material, and loss of mechanical

closure integrity. ! ' . . ..

The applicant did not identify in Section 3.1 of the LRA, or in Table 3.1.2-1, which aging

mechanisms could lead to cracking in low-alloy steel components exposed to an external air

environment. The staff forwarded RAls on the RVinternals and the RCS by letter dated June

11, 2004. In RAI 3.1.2.1-1,-the staff requested additional information on the applicant's AMRs

for managing cracking in low-alloy steel components that are exposed to an external air

environment, particularly because aging management strategies for license renewal are

somewhat dependent on the specific types of aging mechanisms that can induce age-related

degradation, rather than on the general classification of the aging effect.

In response to RAI 3.1.2.1-1, the applicant stated that the low-alloy steel items that are

susceptible to external cracking are limited to fasteners (e.g., RV closure studs) and the exterior

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attachments to vessels. Fasteners are not intentionally exposed to water or steam, but

exposure may result from gasket leaks. If leakage is combined with contaminant species, such

as sulfides or chlorides, an aggressive environment that can promote SCC may result. The

applicant concluded that for the RCS components fabricated from low-alloy steel, including

exterior attachments to vessels and fasteners, cracking at welded joints (i.e., initiation by

fatigue and growth of preservice flaws at welded joints caused by service loadings) is

considered an aging effect requiring management for the period of extended operation. The

Inservice Inspection Program manages cracking. The TLAA for metal fatigue manages

cracking of low-alloy steel RV components by fatigue. The staff finds the applicant's response

acceptable and considers this issue closed.

In RAI 3.1.2.1-4, the staff requested a clarification on where Section 3.1 of the LRA or Table

3.1.2-1 considers the boric acid corrosion aging mechanism. The RAI noted that the

clarification should include which component types, materials, environments, AERMs, and

AMPs are associated with this aging mechanism.

In response to RAI 3.1.2.1-4, the applicant stated that in LRA Section 3.1 and Tables 3.1.2-1

and 3.1.2-3, boric acid corrosion is an applicable mechanism for loss of material for carbon

steel and low-alloy steel components with an external air environment. Carbon and low-alloy

steel components (including all bolting materials, piping and fittings, RCP driver mounts, and

vessels and support skirts) of the RCS that are exposed to an external air environment are

susceptible to loss of material by boric acid corrosion. The Boric Acid Corrosion Prevention

Program, discussed in Section B.1.3 of the LRA, manages this aging effect. The staff finds the

applicant's response acceptable and considers this issue closed.

Low-alloy steel clad with stainless steel and nickel-based alloy exposed to an internal

environment of treated water is subject to loss of material, cracking, and cracking (fatigue).

Low-alloy steel clad with stainless steel and nickel-based alloy exposed to an external

environment of air is subject to loss of material. Low-alloy steel clad with stainless steel

exposed to an internal environment of treated water is subject to loss of material, cracking,

cracking (fatigue), and a reduction in fracture toughness. Low-alloy steel clad with stainless

steel exposed to an external environment of air is subject to loss of material.

Aging Management of Nickel-Based Alloy Components in an Internal Borated Treated Water

Environment. The applicant identified that nickel-based alloy components that are exposed to

an internal environment of treated, borated water are subject to cracking, cracking (fatigue),

and loss of material.

The applicant did not identify in Section 3.1 of the LRA, or in Table 3.1.2-1, which aging

mechanisms could lead to loss of material in nickel-based alloy components. In RAI 3.1.2.1-2,

the staff requested additional information on the applicant's AMRs for managing loss of material

for nickel-based alloy components that are exposed to an internal environment of treated,

borated water.

In response to RAI 3.1.2.1-2, the applicant stated that loss of material can be induced by

crevice and pitting corrosion or by wear in nickel-based alloy components. If RCS fluid

chemistry is not rigorously controlled, the concentration of system fluid contaminants could lead

to loss of material from pitting or crevice corrosion of the nickel-based material. The applicant

addresses this aging effect by maintaining rigorous control of RCS chemistry under the Water

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Chemistry Control Program. Loss of material from wear has the potential to occur between the

nickel-based alloy core-stabilizing lugs and the core barrel. While there has been no operating

experience at ANO-2 showing that wear has occurred in this location, relative motion occurring

from the handling of the vessel internals orthermal expansion during heatup and cooldown

could lead to loss of material as a result of wear.,iiThe Inservice Inspection Program manages

loss of material from wear. Finally, the nickel-based alloy SG U-tubes are subject to loss of

material by sliding wear at tube support locations. iLoss of material by sliding wear occurs when

forces imposed on the tubes by the secondary fluid cause high-frequency vibration of the tubes

and tube support structures. The Steam Generator Integrity Program manages loss of tube

material from wear. The staff finds the applicant's response acceptable and considers this

issue closed.

Aging Manaaement of Stainless Steel Components. The applicant identified that stainless steel

components that are exposed to an external air environment are subject to cracking (fatigue)

and loss of mechanical closure. The applicant identified that stainless steel components that

are exposed to an internal environment of treated, borated water are subject to cracking,

cracking (fatigue), and loss of material.

The applicant did not identify in Section 3.1 of th LRA, or in Table 3.1.2-1, which aging

mechanisms could lead to loss of material in stainless steel components. In RAI 3.1.2.1-3, the.

staff requested additional information on the applicant's AMRs for managing loss of material in

stainless steel components that are exposed to an internal environment of treated, borated

water. ;.

In response to RAI 3.1.2.1-3, the applicant stated that loss of material can be induced by

crevice and pitting corrosion of stainless steel in treated, borated water, if the RCS fluid

chemistry is not rigorously controlled. The applicant addresses this aging effect by. maintaining

rigorous control of RCS chemistry under the Water Chemistry Control Program.

The applicant also stated that various stainless steel components at ANO-2 (e.g., the RV

internals) are subject to flow-induced vibration during plant operation and differential thermal

expansion and contraction movement during plant heatup, cooldown, and changes in power

operating cycles. Flow -induced vibration and thermal expansion can cause repetitive relative

movement between stainless steel interfacing and mating surfaces. This relative movement

between the interfacing and mating surfaces nay result in surface wear. The Inservice

Inspection Program manages loss of material from the wear of these interfacing and mating

surfaces. -The staff finds the applicant's responseacceptable and considers this issue closed.

On the basis of its review of the information provided in the LRA, and the additional information

included in the applicant's response to its RAIs, the staff finds the aging effects of the ab6v6 RV

and CEDM pressure boundary component types are consistent with industry experience for

these combinations of materials and environments. The staff did not identify any missing aging

effects. Therefore, the staff finds that the applicant has identified the appropriate aging effects

for the materials and environments associated with the above components in the RV and

CEDM pressure boundary. -.. . .

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Agina Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program. LRA Table 3.1.2-1 identifies the following AMPs for managing the

aging effects described above for the RV and CEDM pressure boundary:

* Alloy 600 Aging Management Program

* Boric Acid Corrosion Prevention Program

* Reactor Vessel Head Penetration Program*

* Reactor Vessel Integrity Program

* Inservice Inspection Program*

* System Walkdown Program*

* Bolting and Torquing Activities Program

* Water Chemistry Control Program*

The NRC staff reviewed those AMPs identified with an asterisk (*) during an onsite audit.

Sections 3.0.3.3.1, 3.0.3..2.1, 3.0.3.2.6, and 3.0.3.3.2 of this SER document the staff's review

of remaining AMPs.

The applicant proposed to manage loss of material for the following stainless steel,

nickel-based alloy, and low alloy steel clad with stainless steel and nickel-based alloy

component types of the reactor vessel and CEDM pressure boundary system - core stop lugs,

flow skirt, and surveillance capsule holders; penetrations for the CEDM motor housing, CEDM

upper pressure housing, CEDM ball seal housing, CEDM upper pressure housing upper fitting,

CEDM motor housing upper and lower end fittings, CEDM upper pressure housing lower fitting,

CEDM nozzle, ICI nozzle tubes, ICI flange adapter/seal plate, reactor vessel vent pipe, and

reactor vessel vent pipe flange; reactor vessel shell and nozzles for the bottom head (torus and

dome), upper shell, closure head dome (torus and dome), intermediate shell, lower shell, and

primary inlet/outlet nozzle safe ends - exposed internally to treated, borated water using the

primary and secondary water chemistry control program (AMP B.1.30.3). The staff's evaluation

of the primary and secondary water chemistry control program is documented in Section 3.0.3.1

of this SER. The staff concludes that the primary and secondary water chemistry control

program credited by the applicant for this line item is adequate.

For each of these same component and material combinations in Table 3.1.2-1, the applicant is

also managing cracking using the water chemistry control program (AMP B.1.14), inservice

inspection - inservice inspection program (AMP B.1.14), and a plant-specific program such as

Alloy 600 aging management program (AMP B.1;1). The staff's evaluation of the inservice

inspection - inservice inspection - IWB, IWC, IWD, and IWF program is documented in Section

3.0.3.3.5 of this SER. The staff concludes that the inservice inspection - inservice inspection

program credited by the applicant for this line item is adequate. The staff reviewed the

Alloy 600 aging management program and its evaluation is documented in Section 3.0.3.3.1 of

this SER. On the basis of the above discussion, the staff finds that the applicant manages

cracking in a manner consistent with the GALL Report.

On the basis that management of cracking of stainless steel, nickel-based alloy and low alloy

steel clad with stainless steel is being managed by the water chemistry control and inservice

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inspection programs, and the effects'of pitting and crevice corrosion on stainless steel and

nickel-based alloy components are not significant in chemically treated, borated water, the staff

finds that management of loss of material using water chemistry control is adequate.

In the case of the stainless steel CEDM motor housing, upper-pressure housing and fitting, and

ball seal housing as well as the CEDM nickel-alloy fittings, the staff asked-the applicant to justify

application of this position under the low-flow conditions that are expected. The staff reviewed

a report (ML003748904) of maintenance activities that docum6nted site-spe6ific experienc6.

This included a record of the visual inspection bf materials in the same environment that had

been operated under virtually identical conditions without observable loss of material,':

confirming the effectiveness of a water chemistry control program for management of this aging

effect.

On the basis of industry and plant-specific operating experience, and the fact that the applicant

manages the cracking aging effect of these same components, materials, and environment

combinations using water chemistry control and inservice inspection programs, the'staff finds

that the use of a plant-specific water chemistry program to manage loss of material for stainless

steel and nickel-based alloy components exposed to treated, borated water is acceptable.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the component intended functions will be maintained consistent with the CLB

during the period of extended operation.

Conclusion

On the basis of its audit and review, the staff concludes that the applicant has adequately

identified the aging effects, and the AMPs'credited for managing the aging effects, for the RV

and CEDM pressure boundary components so that the component intended functions can be

maintained consistent with the CLB for the period of extended operation, as required by 1 0 CFR

54.21 (a)(3).

The staff also reviewed the applicable UFSAR Supplement program summary descriptions and

concludes that the UFSAR Supplement adequately describes the AMPs credited with managing

aging in these components, as required by 10 CFR 54.21(d).

As stated in the staff's evaluation of the Reactor Vessel Integrity Program, Appendix H to 10

CFR Part 50 requires licensees to submit any proposed changes to their withdrawal schedules

to the NRC for review and approval. As mentioned, Table 5.2-12 of the'ANO-2 LRA contains a

statement that says NRC approval is required, per Appendix H to 10 CFR Part 50,' before

changing removal intervals. To ensure that this requirement will carry forward after the ANO-2

operating license has been renewed, the staff will impose the following license condition in the

renewed license for ANO-2 that requires Entergy to submit any further changes to the

surveillance capsule withdrawal schedule for NRC review'and approval:'

All capsules in the reactor vessel that are removed and tested must meet the

test procedures and reporting requirements of ASTM E 185-82 to the extent

practicable for the configuration of the' specimens in the capsule. Any changes

to the capsule withdrawal schedule' including spare capsules, must be approved

by the NRC prior to implementation. 'All capsules placed in storage must be

3-117
. - -A

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

approved by the NRC.

3.1.2.3.2 Reactor Vessel Internals

Summary of Technical Information in the Application

In Section 3.1.2.1.2 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the AERMs for the RV

internals and associated pressure boundary components:

* Reactor Vessel Internals Cast Austenitic Stainless Steel (CASS) Components Programs

* Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program

* Water Chemistry Control Program

* Inservice Inspection Program

Table 2.3.1-2 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR.

* control element assembly (CEA) instrument tube

* CEA shroud adapter

* CEA shroud support

* positioning plate

* CEA shroud extension shaft guides, cylinders, and bases

* CEA shroud base

* CEA shroud flow channel

* CEA shroud flow channel cap

* CEA shroud shaft retention pin

* CEA shroud retention block

* external spanner nut

* internal spanner nut

* CEA shroud fasteners

* CEA shroud flow channel extension

* CEA shroud tubes

* core shroud'plates

* plates

* ribs2

* intermediate plates

* core shroud guide lugs

* core support barrel (CSB) alignment keys

* CSB assembly dowel pin

2 Note: The core shroud assembly ribs are the vertical members located along the outer surface

(away from the core) of the core shroud assembly. The ribs provide structural stiffness and

support to the core shroud assembly, and are welded in place to provide the appropriate intended

function of the core shroud assembly.

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* CSB lifting bolt insert

* CSB lower flange

* CSB lug

* CSB nozzle

* CSB cylinder

* ~ CSB upperflange , -

* CSB cylinder

* CSB upper flange (continued) -.

* - guide tubes

* ' in-core instrumentation thimble support plate assembly

* '. in-core instrumentation support plate, grid; lifting support, lifting plate, column, plates,

funnel

* pad, ring, nipple, hex bolt, spacer

* threaded rod, hex jam nut, thimble support nut, cap screws

* bottom plate

* bottom plate manhole cover,

*-' cylinder ..

* core support column

* core support plate

* insert pins - * support beam

* support beam flange

* fuel assembly alignment plate (FAP)

FAP guide lug inserts

* holddown ring

* upper guide structure (UGS) support plate

* rUGS cylinder

* -UGS grid plate

* UGS flange

* UGS sleeve -

* . UGS lifting bolt insert-

* UGS alignment keys

* -UGS dowel pins

In Table 3.1.2-2 of the LRA, the applicant provided a summary of AMRs for the RV internals

and associated pressure boundary components and identified which AMRs it considered to be

consistent with the GALL Report. -

Staff Evaluation

The staff reviewed Table 3.1.2-2 of the LRA; which summarized the results of AMR evaluations

in the SRP-LR for the RV internals component groups.

The staff reviewed the AMR of the RV internals component-material-environment-AERM

combinations that are not addressed in the GALL Report or required additional staff review.

These combinations are identified by notes F through J, or plant-specific notes, in LRA Table

3.1.2-2. The NRC staff reviewed those portions of the RV internals that are covered by the

GALL Report (specified by notes A through E in Table 3.1.2-2) during an onsite audit. The staff

t3-119
a

also reviewed the applicable UFSAR Supplements for the AMPs to ensure that the program

descriptions are adequate.

Aging Effects

Aging Management of RV Internals Components Fabricated from Stainless Steel Materials.

Including Cast Austenitic Stainless Steel (CASS). The applicant identified that stainless steel

RV internal components (including CASS) that are exposed to an internal environment of

treated, borated water are subject to loss of material, reduction in fracture toughness, cracking,

cracking (fatigue), and changes in dimension. The applicant identified that loss of mechanical

closure integrity is an additional aging effect requiring management for fastened stainless steel

RV internals components.

The applicant did not identify in Section 3.1 of the LRA, or in Table 3.1.2-1, which aging

mechanisms could lead to loss of material and cracking in CASS RV internals components. In

RAI 3.1.2.2-1, the staff requested additional information on the applicant's AMRs for managing

loss of material and cracking in CASS components that are exposed to an internal environment

of treated, borated water.

In response to RAI 3.1.2.2-1, the applicant stated that if the RCS fluid chemistry is not

rigorously controlled, the concentration of system fluid contaminants could lead to loss of

material from pitting and crevice corrosion of CASS material.

The applicant concluded that CASS material may be susceptible to SCC or to IGA, if exposed

to high concentrations of contaminants in the treated, borated water. In addition, IASCC is a

degradation mechanism for CASS reactor internals items where materials become more

susceptible to SCC with increasing exposure to neutron irradiation. The relatively benign

environment of the RCS fluid, which incorporates hydrogen overpressure to reduce oxygen

levels, reduces the potential for IASCC degradation of the RV internal components made from

CASS materials. Loss of material from pitting or crevice corrosion is also a potential aging

mechanism for CASS reactor internal components in the treated, borated water environment.

The only CASS item in the RV internals is the CEA shroud tube. The applicant credited the

Inservice Inspection Program and the Water Chemistry Control Program with the management

of loss of material and cracking in the CEA shroud tube. The applicant also credited the

Reactor Vessel Internals Cast Austenitic Stainless Steel Components Program with the

management of cracking, as well as loss of fracture toughness from thermal aging, in the CASS

CEA shroud tube. These programs are consistent with industry wide programs for managing

loss of material and cracking for CASS RV internal components and are therefore acceptable

programs to credit for aging management. The staff considers this issue closed. Sections

3.0.3.3.4 and 3.0.3.2.3 of this SER document the staff's evaluation of the ability of the Inservice

Inspection Program and the Water Chemistry Control Program to manage loss of material and

cracking in the CASS CEA shroud tube. The staff evaluates the ability of the Reactor Vessel

Internals Cast Austenitic Stainless Steel Components Program (which is discussed in LRA

Section B.1.22) to manage loss of fracture toughness and cracking in the CASS CEA shroud

tube later in this section of the SER.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects for the above RV internals component types are consistent with industry experience for

3-120
these combinations of materials and environments. The staff did not identify any omitted aging

effects. Therefore, the staff finds that the applicant has identified the appropriate aging effects

for the materials and environments associated with the above components in the' RV internals.:

Aging Management Programs

After evaluating the-'applicant's identification'of aging effects for'each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the'identified

aging effects. The staff also determined that-the'UFSAR Supplement contains an adequate'

description of the program.

LRA Table 3.1.2-2 identifies the following AMPs for managing the aging effects described

above for the RV internals:

* 'Inservice Inspection Program

*' Water Chemistry Control Program

* Reactor Vessel Internals Cast Austenitic Stainless Steel Components Program*

* Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program*

The NRC staff reviewed those AMPs identified by an asterisk () during an onsite audit. Section

3.0.3.3.4 of this SER present the review of the inservice Inspection Program.

The applicant proposed to use the Primary and Secondary Water Chemistry Control Program

(AMP B.1.30.3) to manage loss of material for the following stainless steel component types of

the RV internals system exposed internally to treated, borated water-CEA shroud assembly

components, such as CEA instrument tube;, CEAshroud adapter, CEA shroud support,

positioning plate, CEA shroud flow channel extension, and core shroud tube; core shroud

assembly components, such as core shroud plates, plates, ribs, intermediate plates, and core

shroud guide lugs; and in-core instrumentation components, such as guide tubes, in-core

instrumentation thimble support plate assemrrbly, in-core instrumentation support plate,'grid,

lifting support, lifting plate, columns, platesi funnel, pad, ring, nipple; hex bolt, spacer, threaded

rod, hex jam' nut, thimble support nut, and cap screws. Section 3.0.3.1 of this SER documents

the staff's evaluation of the Primary and Secondary Water Chemistry Control Program. The

staff concludes that the Primary and Secondary Water Chemistry Control Program credited by

the applicant for this line item is adequate,

For each of these same component and material combinations in LRA Table 3.1.2-2, the

applicant is also managing cracking using theWater Chemistry Control Program, the Irservice

Inspection-Inservice Inspection Program (AMP B.1i.14), and a plant-specific program, such as

the Reactor Internals Stainless Steel Prograrn- Section 3.0.3.3.5 of this SER documents the'

staff's evaluation of the Inservice Inspection-Inservice Inspection Program (ASME Code

Subsections IWB, IWC, IWD, and IWF). The 'staff concludes that the Primary and Secondary

Water Chemistry Control Program credited by the applicant for this line item is adequate.

Section 3.0.3.1 of this SER documents the staff's review of the Rea6tor Vessel Internals

Stainless Steel Plates, Forgings, Welds, and Bolting Program (AMP B.1 23). On the basis6of

the above discussion, the staff finds that the appliciant manages cracking in a'manneri'

consistent with the GALL Report.

'3-'121
Because the applicant is managing cracking of stainless steel by the Water Chemistry Control

and the Inservice Inspection Programs, and the effects of pitting and crevice corrosion on

stainless steel components are not significant in chemically treated, borated water, the staff

finds that management of loss of material using water chemistry control is adequate.

The GALL Report recommends a loose parts monitoring program to manage loss of

mechanical closure integrity for CEA shroud extension shaft guides, cylinders, and bases;

shroud base; shroud flow channel; shroud flow channel cap; shroud shaft retention pin; shroud

retention block; spanner nuts; shroud fasteners; guide tubes; in-core instrumentation thimble

support plate assembly; in-core instrumentation support plate, grid, lifting support, lifting plate,

column, plates, and funnel; pad, ring, nipple, hex bolt, spacer; threaded rod, hex jam nut,

thimble support nut, cap screws, and RV internals.

The applicant proposed to manage this aging effect using the Reactor Vessel Internals

Stainless Steel Plates, Forgings, Welds, and Bolting Program (AMP B.1.23) and the Inservice

Inspection-Inservice Inspection Program (AMP B.1.14). Sections 3.0.3.1 and 3.0.3.3.5 of this

SER, respectively, document the staff's review of these programs. The staff concludes that the

Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting Program and the

Inservice Inspection-Inservice Inspection Program credited by the applicant for this line item

are adequate.

On the basis that the Reactor Vessel Internals Programs detect aging effects before the loss of

mechanical integrity of these components, the staff finds that their use, in lieu of a loose parts

monitoring program, is acceptable. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the component intended functions will be

maintained consistent with the CLB during the period of extended operation.

Conclusion

On the basis of its audit and review, the staff concludes that the applicant has adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

reactor vessel internal components so that the component intended functions can 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.1.2.3.3 Class 1 Piping, Valves, and Reactor Coolant Pumps

Summary of Technical Information in the Application

In Section 3.1.2.1.3 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the Class 1 piping, valves, and RCP and the associated pressure boundary

components:

* Water Chemistry Control

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* Inservice Inspection

* Cast Austenitic Stainless Steel

* Boric Acid Corrosion Prevention

* Alloy 600 Aging Management

* Bolting and Torquing Activities : H ,

Table 2.3.1-3 of the LRA lists the following individual system components within the scope of

license renewal and subject to an AMR:

* :charging inlet nozzle

* safety injection nozzle

* surge line nozzle

* charging inlet nozzle safe end

* drain nozzle safe end

* letdown nozzle safe ends,

* 'pressure measurement nozzle safe'end

* sampling nozzle safe end

* charging inlet nozzle thermal sleeve

* safety injection nozzle thermal sleeve

* surge line thermal sleeve '

* .' ..ASME Code Class .1 boundary orifices

* -ASME Code Class 1 pipe and fittings NPS less than 4 inches

* :ASME Code Class 1 pipe NPS greater than or equal to 4 inches

* : - ASME Code Class 1 fittings I' .

* cold-leg piping and elbows

* hot-leg pipe and elbows . :,. . -.. : .,; 

* drain nozzles

* letdown nozzles

* shutdown cooling outlet nozzle

* ~-spray nozzle

* pressure measurement nozzle .

* replacement pressure nozzle .

* sampling nozzle

* RCP safe ends, . * resistance temperature device (RTD) nozzles, -

* safety injection nozzle safe end . -.

* shutdown cooling outlet nozzle safe end

* 1'- surge nozzle safe end ,

* stainless steel bolting . - -

* surge line pipe and elbows

* surge line piping: RTD and sampling nozzles

* ' carbon/alloy steel bolting ; -:

* valve bodies and bonnets .-

* ASME Code Class 2 and 3 closure bolting

* ASME Code Class 2 and 3 fittings'

* ASME Code Class 2 and 3 pipe

* ASME Code Class 2 and 3 valve bodies and bonnets

* tubing *..

* ,RCP casing . ..

3-123
* RCP cover

* RCP cover studs

* RCP cover nuts

* RCP driver mount assembly

* RCP thermal barrier heat exchanger inner coil

* RCP thermal barrier heat exchanger outer coil

* RCP thermal barrier bored hole heat exchanger

In Table 3.1.2-3 of the LRA, the applicant provided a summary of the AMRs for the Class 1

piping, valves, and RCP and the associated pressure boundary components and identified

which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.1.2-3 of the LRA, which summarizes the results of the AMR

evaluations in the SRP-LR for the Class 1 piping, valves, and RCP component groups. The

staff finds that the programs proposed for management of the aging effects for the component

types in this system are consistent with the GALL Report.

The NRC staff reviewed the AMR of the ASME Code Class 1 piping, valves, and RCP

component-material-environment-AERM combinations that are not addressed in the GALL

Report, or required additional staff review. Table 3.1.2-3 identifies these combinations by notes

F through J, or plant-specific notes. The NRC staff reviewed those portions of the ASME Class

1 piping, valves, and RCPs that are covered by the GALL Report (specified by notes A through

E in Table 3.1.2-3) during an onsite audit. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Aging Management of ASME Code Class 1 Piping. Valve. Pump and Fitting Components

Fabricated from Carbon Steel and Low-Alloy Steel Materials. The surfaces of carbon steel

components that are clad internally with stainless steel and are exposed to an internal

environment of treated, borated water are subject to the aging effects of loss of material,

cracking, and cracking (fatigue). The surfaces of carbon steel components, including carbon

steel components with internal stainless steel cladding, that are exposed to an external air

environment are subject to the aging effects of loss of material and cracking (fatigue).

Low-alloy steel components exposed to an external environment of air are subject to the aging

effects of loss of material, cracking, cracking (fatigue), and, for low-alloy steel bolting

components, loss of mechanical closure integrity.

Aging Manaqement of ASME Code Class 1 Piping. Valve. Pump and Fitting Components

Fabricated from Nickel-Based Alloy and Stainless Steel Materials, Including CASS. The

applicant identified that nickel-based alloy components that are exposed to an internal

environment of treated, borated water are subject to the aging effects of loss of material,

cracking, and cracking (fatigue).

The applicant identified that stainless steel components that are exposed to an internal

environment of treated, borated water are subject to the aging effects of loss of material,

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cracking, and cracking (fatigue).' The applicant identified that stainless steel exposed to an

external environment of air is subject to the aging effects of cracking, cracking (fatigue), :,-.

reduction in fracture toughness (17-4PH [precipitation-hardened] material only), and loss of

mechanical closure integrity. The applicant identified that stainless steel components exposed:

to an external environment of treated water are subject to the aging'effects of loss of material,

cracking, and cracking (fatigue).

The applicant identified that CASS components that are exposed to an internal environment of

treated, borated water or a treated water external environment are subject to the aging effects

of loss of material, cracking, cracking (fatigue), and reduction in fracture toughness.

In LRA Table 3.1.2-3, page 3.1-79, the applicant identified treated water as the external,

environment for the RCP thermal barrier heat exchanger inner coil. In addition, on page 3.1-80,

the applicant identified treated water as the internal environment for the RCP thermal barrier

heat exchanger outer coil and bored-hole heat exchanger. The aging effects of loss of material,

cracking, and fatigue require aging management.

The AMPs identified to manage these aging effects are the Inservice Inspection Program and

the Time-Limited Aging Analysis (TLAA)-Metal Fatigue. The applicant's Auxiliary Systems

Water Chemistry.Control Program, described in Section B.1.30.1, identifies its purpose as

managing loss of material, cracking, and fouling of components exposed to treated water

systems. The applicant has identified similar components of the same material which'are

exposed to the same environment as being managed by a water chemistry AMP and

referenced concurrence with the GALL Report, Section VII.C2.2-a. In RAI 3.1.2-3.1, the staff,

requested that the applicant provide justification for excluding an AMP to manage the water

chemistry of the treated water environment, as applicable to these components.. -

In response to RAI 3.1.2-3.1, the applicant stated that the treated water identified in the ANO-2

LRA which supplies cooling to the RCP thermal barrier heat exchangers is part of the ANO-2

component cooling water (CCW) system. Th6 chemistry controls for this system are not

sufficiently rigorous to control the contaminants which could potentially lead to loss of material

and cracking in the RCP thermal barriers. Therefore, the Component Cooling Water Chemistry

Control Program is not credited as managing these aging effects. The applicant concluded that

the Inservice Inspection Program will manage these aging effects such that corrective action

may be taken before a loss of the component intended function. The staff finds the applicant's

response acceptable and considers this issue closed.

On the basis of its review of the information, provided in the LRA, and the additional information

included in the applicant's response to the above RAI, the staff finds the aging effects for the

ASME Code Class 1 piping, valves, and RCPs are consistent with industry experience for these

combinations of materials and environments. -The staff did not identify any omitted aging

effects. Therefore, the staff finds that the applicant has identified the appropriate aging effects

for the materials and environments associated with the above components in the ASME Code

Class 1 piping, valves, and RCPs.

Aging Manaaement Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

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aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.1.2-3 identifies the following AMPs for managing the aging effects described

above for the ASME Code Class 1 piping, valves, and RCPs:

* Inservice Inspection Program

* Water Chemistry Control Program*

* Alloy 600 Aging Management Program

* Boric Acid Corrosion Prevention Program

* System Walkdown Program*

* Cast Austenitic Stainless Steel (CASS) Evaluation Program*

* Bolting and Torquing Activities Program

The NRC staff reviewed those AMPs identified by an asterisk (*) during an onsite audit.

Sections 3.0.3.3.4, 3.0.3.3.1, 3.0.3.2.1, and 3.0.3.3.2 of this SER document the staff's

evaluation of remaining AMPs.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the Class 1 piping,

valves, and RCP component types. In addition, the staff finds the program descriptions in the

UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited for managing them for the ASME Code

Class 1 piping, valves, and RCPs so that there is assurance that the component 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.1.2.3.4 Pressurizer

Summary of Technical Information in the Application

In Section 3.1.2.1.4 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the pressurizer and associated pressure boundary components:

* Water Chemistry Control Program

* Pressurizer Examinations Program

* Inservice Inspection Program

* Boric Acid Corrosion Prevention Program

* Alloy 600 Aging Management Program

* Bolting and Torquing Activities Program

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* Cast Austenitic Stainless Steel (CASS) Evaluation Program

Table 2.3.1-4 of the LRA lists the following individual system components within the scope of

license renewal and subject to an AMR: . ' - i- I

0

S

0

0

0

0

0

0

0

0

0

0

0

0

0

S

S

0

0*

0

0

S

S

S

S

S

S

S

0,

0

0

S

S

heater end plug

heater sheaths

heater sleeves :

heater support channel.

heater support plates

heater support plate brackets

-heater support plate bracket bolts

lowerhead.

lower shell

upper shell

upper head

lower level nozzle

manway cover bolts/studs

manway cover plate

manway forging -

manway gasket retainer plate .,

mechanical nozzle seal assembly (MNSA) bolting (studs, nuts, and washers),

MNSA compression collar

MNSA upper flanges

pressure measurement nozzle

upper-level nozzle

vent nozzle - , .

temperature nozzle

pressure measurement nozzle safe end,

upper/lower-level nozzle safe end

vent nozzle safe end

temperature nozzle safe end

safety valve nozzle

spray nozzle ,

surge nozzle ,.

safety valve nozzle flange

spray nozzle safe end

spray nozzle thermal sleeve

support skirt , . , i

surge nozzle safe end , , : * .'.

I

In Table 3.1.2-4 of the LRA, the applicant provided a summary of AMRs for the pressurizer and

associated pressure boundarycomponents and identified which AMRs it considered to be

consistent with the GALL Report.

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Staff Evaluation

The staff reviewed Table 3.1.2-4 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the pressurizer component groups.

The technical staff reviewed the AMR of component-material-environment-AERM combinations

for the pressurizer components that are not addressed in the GALL Report, or required

additional staff reviews. These combinations are identified by notes F through J, or plantspecific notes, in LRA Table 3.1.2-4. The NRC staff reviewed those portions of the pressurizer

that are covered by the GALL Report (specified by notes A through E in Table 3.1.2-4) during

an onsite audit. The staff determined that the applicant identified all applicable AERMs and

credited the appropriate AMPs for managing them. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Aging Management of Pressurizer Components Fabricated from Nickel-Based Alloy or

Stainless Steel Materials. Including CASS. The applicant identified that nickel-based alloy

components (including the cladding of low-alloy steel pressurizer components that are clad

internally with nickel-based alloy materials) that are exposed to an internal environment of

treated, borated water are subject to the aging effects of loss of material, cracking, and

cracking (fatigue).

The applicant identified that stainless steel components (including CASS and the cladding of

low-alloy steel pressurizer components that are clad internally with stainless steel materials)

that are exposed to an internal environment of treated, borated water are subject to the aging

effects of loss of material, cracking, and cracking (fatigue). The applicant identified that for

CASS components that are exposed to an internal environment of treated, borated water,

reduction in fracture toughness as a result of thermal aging is an additional aging effect

requiring management. The applicant identified that stainless steel components that are

exposed to an external environment of air are subject to the aging effects of cracking and

cracking (fatigue).

The applicant did not identify in Section 3.1 of the LRA, or in Table 3.1.2-4, which aging

mechanisms could lead to cracking in stainless steel components. In RAI 3.1.2.4-2, the staff

requested that the applicant provide additional information on the AMRs for managing cracking

in stainless steel components that are exposed to an external air environment. In response to

RAI 3.1.2.4-2, the applicant stated that generally, stainless steel exposed to an external air

environment is not susceptible to aging effects requiring management. Insulation material used

for RCS components has low soluble chloride and other halide content to minimize the

possibility of SCC of stainless steel components. However, stainless steel items, such as

flange and valve bolting, in air are subject to cracking, as indicated in Table 3.1.2-3 on page

3.1-68 of the LRA. Stainless steel fasteners are not intentionally exposed to water or steam,

but exposure may result from gasket leaks. If leakage is combined with contaminant species,

such as sulfides or chlorides, an aggressive environment that can promote SCC may result.

Therefore, the applicant concluded that cracking of stainless steel flange and valve bolting is

considered an AERM for the period of extended operation. Even though cracking is not

expected, the Inservice Inspection Program is credited to confirm the absence of cracking

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resulting from SCC. The staff finds the applicant'sresponse acceptable and considers this'

issue closed.

The applicant also did not identify'in 'Section 3.1 of the LRA, or in Table 3.1.2-4, which aging

mechanisms could lead to loss of material ard'cracking in the cladding of low-alloy steel

pressurizer components that are clad either with stairnless steel or nickel-based alloy and are'

exposed to an internal environment of treated, borated water. In RAI 3.1.2.4-3, the staff

requested that the applicant provide additional information on the AMRs for managing loss of

material and cracking in the cladding materials that are exposed to an internal environment of

treated, borated water.

In response to RAI 3.1.2.4-3, the applicant stated that the stainless steel cladding and -

nickel-based alloy cladding are susceptible to 'cracking' by SCC and PWSCC, respectively.' The

applicant also stated that both the stainless'steel'cladding and nickel-based alloy cladding are

susceptible to loss of material by crevice or pitting corrosion, which is consistent with the

applicant's responses to RAls 3.1.2.1-2 arid 3.1.2.1-3 'on corresponding materials in the'ANO-2

RV. -;

In RAI 3.1.2.4-5, the staff inquired as to how the applicant was managing cracking, and

specifically PWSCC,'in the nickel-based penetration nozzles of the ANO-2 pressurizer and any

associated nickel-based alloy weld materials.' In response to RAI 3.1.2.4-5, the6applicant stated

that nickel-based alloy penetrations associated with the ANO-2 pressurizer include'pressure

measurement,'vent,- level, and teinperatbr''nozzles; heater pen-etratidn nozzlesand plugs; and

Alloy 82/182 welds. All of these nickel-based alloy items are exposed to treated, borated water

and are susceptible to PWSCC. A combiriation of the Inservice Inspection Program,'the Water

Chemistry Control Program, and the All6y'60O'Aging"Management Program manages this

aging effect'X Sections B.1.14, B.1.30, and 1.1.1,; respectively, of the ANO-2 LRA discuss the

details of these programs, including scop&';fr6quency, technique, acceptance'criteria, and thetechnical basis for future examinations. These programs represent industry norms for '

managing PWSCC of nickel-based alloy base-metal and weld components and are acceptable

programs to credit for management of PWSCC'in the nickel-based alloy base-metal and weld

components in the 'ANO-2 pressurizer system. -The staff finds the applicant's response

acceptable and considers this issue closed.?' Se6tions 3.0.3.3.4 and 3.0.3.2.8 of this SER,

respectively, present the staff's evaluation of the 'nservice Inspection Program and the Water

Chemistry Control Program. Section'3.0.3 3.1 'of this SER presents the staff's'evaluation of the

Alloy 600 Aging Management Program.

Aging Management in Carbon Steel and Lw6-Allov Steel Pressurizer Components. The''

applicant identified that carbon steel compdne'nts exposed to an external environment of air are

subject to the aging effects of loss of material, cracking, and cracking (fatigue). -

The applicant identified that low-alloy steel 'o-mponents exposed to an external environmeht of

air are subject to the aging effects of loss of material, cracking, cracking (fatigue), and loss of

mechanical closure integrity. The applicant also identified that unclad low-alloy steel (lower

'3-1 29
A

head only) exposed to an external environment of treated, borated water experiences the aging

effect of loss of material.

The applicant did not identify in Section 3.1 of the LRA, or in Table 3.1.2-4, which aging

mechanisms could lead to cracking in carbon steel components. In RAI 3.1.2.4-1, the staff

requested that the applicant provide additional information on the AMRs for managing cracking

in carbon steel components that are exposed to an external air environment.

In response to RAI 3.1.2.4-1, the applicant referred to its response to RAI 3.1.2.1-1, which

concluded that for the RCS components fabricated from low-alloy steel, including exterior

attachments to vessels, cracking at welded joints (initiated by fatigue and growth of preservice

flaws at welded joints caused by service loadings) is considered an aging effect requiring

management for the period of. extended operation. Thus, to respond to RAI 3.1.2.4-1, the

applicant extended the applicability of the discussion in its response to RAI 3.1.2.1-1 (as it

pertains to cracking of low-alloy steel RCS components) to the surfaces of carbon steel

pressurizer components that are exposed to the external air environment and considers

cracking to be an AERM for the carbon steel pressurizer components.

For the underlying ferritic steel in the pressurizer (i.e., the low-alloy steel heads and shells in the

pressurizer), service loadings may result in the growth of preservice flaws or initiation and

growth of service-induced flaws. Cracking at the welded low-alloy steel joints is considered an

aging effect requiring management for the period of extended operation. The applicant

concluded that growth of fabrication flaws caused by service loads is the bases for the ASME

Code, Section Xl, inspections, as documented in EPRI NP-1406-SR, "Nondestructive

Examination Acceptance Standards." The applicant credited the Inservice Inspection Program

to manage this particular aging effect. Because the applicant is managing this aging effect

through application of the recommendations of the EPRI standard, as implemented through the

Inservice Inspection Program, the staff concludes that the applicant's response is acceptable

and considers this issue closed.

The applicant credits the Inservice Inspection Program to manage cracking of the carbon steel

and low-alloy steel pressurizer components in general. The applicant also credits the TLAA on

metal fatigue of ASME Code Class 1 components to manage cracking that is induced by

thermal fatigue of these components. These programs are consistent with industry norms for

managing cracking in these components. The staff finds the applicant's response acceptable

and considers this issue closed.

Table 3.1.2-4, page 3.1-84, identifies the pressurizer lower head, lower shell, upper shell, and

upper head as component types. The applicant identified the aging effect of loss of material,

and specified that it is applicable to the unclad low-alloy steel of the lower head only. In RAI

3.1.2.4-4, the staff requested the applicant to justify limiting the aging effect to only the lower

head, since many components of the pressurizer are susceptible to boric acid corrosion in a

3 The environment discussed in this sentence refers to the environmental condition that results

either from installation of a mechanical nozzle seal assembly repair method or half-nozzle

replacement design. These repair/replacement methods leave the underlying ferritic (low-alloy steel) materials adjoined to the repaired pressurizer nozzle exposed to the reactor coolant (i.e., treated, borated water environment). The applicant considers this to be an external environment.

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treated, borated water environment and would require the aging effect of loss of material to be

managed.

In response to RAI 3.1.2.4-4, the applicant stated that Table 3.1.2-4, page 3.1-84, identifies loss

of material as an aging effect requiring management for unclad lower vessel head low-alloy,

steel exposed to treated, borated water. The applicable locations for this table entry are heater

nozzle penetrations that have been repaired. An Alloy 600 nozzle may contain a through-wall

flaw that exposes the underlying ferritic steel to treated, borated water. These locations are

susceptible to loss of material caused by exposure to treated, borated water. In addition, LRA

Table 3.1.2-4 identifies loss of material for low-alloy steel pressurizer items exposed to air with

the potential for leaking borated water. Table 3.1.2-4, page 3.1-83, of the LRA, identifies the

ANO-2 pressurizer upper head, upper shell, lower head, and lower shell identified as f

susceptible to loss of material caused by boric acid corrosion in an external air environment.

The staff finds the applicant's response acceptable and considers this issue closed..

In Table 3.1.2-4 of the ANO-2 LRA, the applicant identified pressurizer component types, the

aging effects requiring management, and the AMPs that will manage these aging effects.

Recent operational experience at both domestic and foreign facilities (i.e., Palo Verde, Units 2

and 3; Millstone, Unit 2; Waterford, Unit 3; and Tsuruga, Unit 2 in Japan) has shown that

leakage of pressurizer penetrations from PWSCC is an aging effect that requires management.

.In light of the recent industry experience, and the limited scope of the Pressurizer Examinations

Program, the staff requested, in RAI 3.1.2.4-5, that the applicant discuss how it will manage the

aging effect of PWSCC for the pressurizer penetrations during the period of extended

operation.

With regard to the installation of MNSAs as alternative repair methods, the NRC staff believes

that, should an applicant decide to keep an MNSA in service beyond the period for which

temporary approval has already been granted, the applicant must provide a justification which

supports the approval of the MNSA, either as a temporary repair for the facility or as a

permanent repair for the facility. The applicant's justification should be submitted against the

alternative ISI provisions of 10 CFR 50.55a(a)(3), and should include an analysis of the

pressure boundary component to which the MNSA is attached, an assessment of all age- ;

.related mechanisms that may be applicable to the MNSA design and to all ferritic and nickelbased alloy components to which the MNSA installation is applicable, and a proposed

alternative ISI program for the MNSA, which is to be maintained for the NRC-approved period

(i.e., for the period of approval if the MNSA is approved as a temporary repair, or throughout

the licensed life of the facility if the MNSA is approved as a permanent repair for the facility).

The applicant should submit its justification to the NRC for review and approval no later than-1

year before the expiration of its existing temporary repair approval period. ;;;

On the basis of its review of the information provided in the LRA, and the additional information

included in the applicant's response to the above RAIs, the staff finds that the aging effects of

the pressurizer component types are consistent with industry experience for these,

combinations of materials and environments. The staff did not identify any omitted aging

effects. Therefore, the staff finds that the applicant has identified the appropriate aging effects

for the materials and environments associated with the components in the pressurizer. .;* I . , . . ' . ,i .. ;. . ..

- . , . .

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Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.1.2-4 identifies the following AMPs for managing the aging effects described

above for the pressurizer:

* Inservice Inspection Program

* Water Chemistry Control Program

* Pressurizer Examinations Program*

* Alloy 600 Aging Management Program

* Boric Acid Corrosion Prevention Program

* System Walkdown Program*

* Cast Austenitic Stainless Steel (CASS) Evaluation Program*

* Bolting and Torquing Activities Program

The NRC staff reviewed those AMPs identified with an asterisk (*) during an onsite audit.

Sections 3.0.3.3.4, 3.0.3.2.8, 3.0.3.3.1, 3.0.3.2.1, and 3.0.3.3.2 of this SER document the staff's

review of remaining AMPs.

During the review, the staff noted that the applicant had not credited the Inservice Inspection

Program (AMP B.1.14) for managing the cracking of pressurizer safe ends. The staff

requested the applicant to correct this discrepancy.

By letter dated March 24, 2004, the applicant committed to using the Inservice Inspection

Program to manage cracking of the pressurizer safe ends. This is now consistent with the

GALL Report and acceptable to the staff.

For loss of material from the nickel-alloy pressurizer heater support plates and support brackets

exposed to treated, borated water, the applicant credited the Water Chemistry Control Program.

Section 3.0.3.1 of this SER documents the staff's evaluation of this AMP. The staff concludes

that the Water Chemistry Control Program credited by the applicant for this line item is

adequate.

On the basis of industry operating experience with this material and use of a water chemistry

control program consistent with the GALL Report, the staff found this acceptable.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate the AMPs for managing the aging effects of the pressurizer

component types.

Conclusion

On the basis of its audit and review, the staff concludes that the applicant has adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

pressurizer components so that the component intended functions can be maintained

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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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.1.2.3.5 Steam Generators

Summary of Technical Information in the ApDlication

In LRA Section 3.1.2.1.5, the applicant identified the following materials, environments, aging,;

effects, and associated AMPs related to the SG components that are within the scope of the

LRA. LRA Table 3.1.2-5 lists the SG components that require an AMR, which are discussed

below.. -

Steam generator components are constructed of the following materials:

* low-alloy steel clad with stainless steel --

* -low-alloy steel clad with nickel-based alloy

* low-alloy steel

* carbon steel

* stainless steel

* nickel-based alloy

Steam generator components are exposed to the'following environments: .. - . A.

* .. air

* treated, borated water on the primary side of the steam generators

* treated water on the secondary side of the steam generators, which includes steam

Steam generator components may experience the following aging effects:

* . cracking. . -

* loss of material )--

. fouling

* loss of preload/mechanical closure integrity '

The above aging effects will be managed by the following AMPs: , ;

* Water Chemistry Control Program

* Inservice Inspection Program

* Boric Acid Corrosion Prevention Program: .

* Alloy 600 Aging Management Program'.

* Bolting and Torquing Activities Program u

* Steam Generator Integrity Program,,-

* Flow-Accelerated Corrosion Program. - -

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In Table 3.1.2-5 of the LRA, the applicant provided a summary of AMRs for the SGs and

associated pressure boundary components and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.1.2-5 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the SG component groups.

Aging Effects

The staff finds that the materials, environments, and aging effects associated with the SG

components detailed in LRA Section 3.1.2.1.5 are acceptable because they are consistent with

the SRP-LR and the GALL Report. In addition, they are consistent with the operating

experience of these components. Various sections of this SER discuss the staff's review of the

above AMPs related to the SG components.

The applicant replaced the two original steam generators with Westinghouse Delta 109s steam

generators in the fall of 2000. Several corrosion mechanisms have been identified in operating

SGs in the industry that can result in unacceptable tube degradation. The ANO-2 replacement

SG design addresses these degradation mechanisms and provides a design that is resistant to

tube corrosion. Given that appropriate water chemistry is maintained, the SGs are designed for

a cumulative operating service of 40 years.

The tube material, tubing fabrication methods, and installation techniques minimize corrosion in

the tubes. The replacement SGs contain thermally treated nickel-chromium-iron Alloy 690

tubes that are 11/16 inch in diameter with a 0.040-in. wall thickness. The tubes undergo a

laboratory-derived thermal treatment process following tube-forming operations. The thermal

treatment subjects the tubes to elevated temperatures for a prescribed period of time to

improve the grain structure of the material. Laboratory tests and operating experience in

nuclear power plants have shown thermally treated Alloy 690 to be resistant to PWSCC and

ODSCC.

Industry corrosion tests subjected the SG tubing material to simulated SG water chemistry.

These tests indicated that the loss from general corrosion over the 40-year operating design

objective is small compared to the tube wall thickness. Testing to investigate the susceptibility

of heat exchanger construction materials to stress corrosion in caustic and chloride aqueous

solutions (more aggressive than reactor water conditions) indicate that the Alloy 690 material

provides as good or better corrosion resistance as either Alloy 600 or nickel-iron-chromium

Alloy 800.

The replacement SG design features minimize the potential for concentration of chemical

species in crevices or contact areas between tubes and tubesheet or other internals that can be

detrimental to high nickel-alloy tubing material. All tubes are initially tack expanded on the tube

end, welded to the tubesheet cladding, then expanded into the tubesheet for the full depth of

the tubesheet bore by the hydraulic expansion process. This process has the advantages of

expanding the tube into essentially metal-to-metal contact with the tubesheet bore, without

excessively cold working the tube wall. In addition, the full-depth expansion joint minimizes

crevices between the tube and tubesheet.

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The tube support plates are constructed of stainless'steel and are a broached trefoil-hole

design. The tube support plates are sized to provide sufficient strength to ensure that the tubes

maintain structural integrity during a seismic event. The clearance between the tube and tube

support, and the spacing between the supports; is sized to minimize the potential for excessive

vibration'of the tubes. The tube support plates are made of corrosion resistant Type 405 ferritic

stainless steel. Use of this material minimizes the potential for corrosion of the tube support

plates, thus minimizing tube denting. The tube'support design reduces the tube-to-tube support

plate crevice area, while providing for maximum steam and water flow in the open areas

adjacent to the tube.

The upper bundle supports consists of five sets .of staggered stainless steel antivibration bars.

Antivibration bars installed in the U-bend portion of the tube bundle' minimize the potential for

excessive tube vibration. The antivibration bars are fabricated from Type 405 stainless steel.

The SG shell is constructed of low-alloy steel. Manways and handhold openings in the shelf

provide access to the SG internal structures. -.Manways on the inlet and outlet side of the

channel head permit access to the tubesheet for inspection and tube plugging, if required.

Reactor coolant enters the primary side of the SGs through the 42-in. inside diameter inlet

nozzle, flows through tubes, and leaves through'two, 30-in. inside diameter outlet nozzles. A,

divider plate in the channel head separates the inlet and outlet plenums. The channel head is a

low-alloy steel forging with low-cobalt stainless steel cladding. The tubesheet is low-alloy steel

with the reactor coolant side of the tubesheet clad with nickel-chromium-iron Alloy 690.

Feedwater enters the secondary side of the SGs through the feedwater nozzle where it is

distributed via an elevated feedwater distribution' ring which directs the flow into the downcomer.

The downcomer is the annular passage formed by the inner surface of the SG shell and the:.

cylindrical wrapper that encloses the tubes. :The feedwater distribution ring is welded to the

feedwater nozzle to minimize the potential for draining the ring. The connection between the

nozzle and the feedwater ring is a thermal sleeve that minimizes the effect of cold feedwater

addition transients on the feedwater nozzle. The feedwater ring is located above the elevation

of the feedwater nozzle to minimize the time required to fill the feedwater nozzle during a cold

water addition transient. The feedwater is discharged through inverted J-nozzles installed on

the top of the ring. These features reduce the thermal fatigue loading on the feedwater nozzle,

eliminate steady-state thermal stratification in the feedwater nozzle and feedwater piping elbow

at the feedwater nozzle entrance, and minimize the potential for bubble collapse water hammer

generated in the feedwater distribution ring.

Steam Generator Components in LRA Table 3.1.1 Requiring Further Evaluation

LRA Table 3.1.1 summarizes the AMPs for the RCS, including SG components. The staff

reviewed SG-related items in LRA Table 3.1.1 to determine their acceptability in the AMR. The

following items in LRA Table 3.1.1 need further evaluation or clarification.

For Item 3.1.1-2, the applicant identified the Inservice Inspection Program to manage loss of

material from pitting and crevice corrosion in the SG shell assembly. IN 90-04 states that the.:

ASME Code, Section XI, inservice inspection method may not be sufficient to detect general

and pitting corrosion in'the shell/transition cone'welds. The applicant stated that the concerns

of IN 90-04 are not applicable to SGs because they.were replaced in 2000, and pitting corrosion

:3-135
a

of the SG shell is not currently known to exist. However, the staff believes that the current

operating experience does not provide assurance that pitting will not occur at the shell

assembly in the future. In the absence of corrosion tests to demonstrate that the shell and

transition cone would not develop pitting corrosion at the end of the extended period of

operation, the applicant should assume pitting and general corrosion and implement inspection

methods to detect such corrosion. In RAI 3.1.1-1, the staff asked the applicant to clarify

whether it will implement any procedures, in addition to the ASME Code, to inspect the shell

assembly, including transition cone, in the ANO-2 SGs for pitting and general corrosion.

By letter dated July 1, 2004, the applicant responded that the rules of Section Xl of the ASME

Code require a volumetric examination of one upper shell-to-transition cone weld during each

10-year inspection interval. However, IN 90-04 states that if general corrosion pitting of the SG

shell is known to exist, the requirements of Section Xl of the ASME Code may not be sufficient

to differentiate isolated cracks from inherent geometric conditions. IN 90-04 indicates that the

degradation probably results from corrosion-assisted thermal fatigue caused by relatively cold

water impinging upon the weld region during reactor trips from full-power and certain transient

operations.

The applicant further stated that localized corrosion is heavily dependent on contaminants for

initiation and propagation. The ANO-2 Water Chemistry Control Program limits these

contaminants, which precludes localized corrosion. The program relies on monitoring and

control of water chemistry based on the guidelines in TR-1 02134 for secondary water

chemistry. In addition, the shell-to-transition cone welds in the replacement SGs have low

cyclic stress (thermal fatigue) levels with a cumulative usage factor of 0.15. The applicant

installed the replacement SGs in 2000, with a design life extending to 2040, which is beyond the

period of extended operation ending in 2038. The applicant believes that the corrosion

mechanisms described in IN 90-04 are not applicable to the replacement SGs because of the

control of water chemistry. Therefore, the applicant believes that no additional inspections are

required for the shell-to-transition cone weld for the period of extended operation.

The staff finds the applicant's response acceptable because the shell-to-transition cone welds

in the replacement SGs have an acceptable cumulative usage factor (0.15), as compared to the

ASME Code allowable cumulative usage factor of 1.0. This indicates that the cyclic stresses

are low, which will minimize cracking, and the Water Chemistry Control Program is based on

guidelines in TR-1 02134, which will minimize localized corrosion at the shell-to-transition cone

welds.

For Items 3.1.1-19 and 3.1.1-20, the applicant stated that the SGs do not have carbon steel

tube support plates and carbon steel tube support lattice bars, respectively. By letter dated July

1, 2004, in its response to RAI 3.1.1-2, the applicant clarified that the SG tubes are supported

by tube support plates maintained in place with a system of stayrods and spacer pipes. The

support plates are fabricated from stainless steel; the stayrods and spacer pipes are fabricated

from carbon steel. The U-bend portions of the tubes are supported by a system of antivibration

bars fabricated from stainless steel. These items are all subject to an AMR and are included in

LRA Table 3.1.2-5. The staff finds the applicant's response acceptable because the applicant

has clarified the tube support system.

For Item 3.1.1-21, the applicant stated that the feedwater ring discussed in the GALL Report

(e.g., Section IV.D1.3-a) is applicable to CE System 80 steam generators and is not applicable

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to the Westinghouse steam generators at ANO-2. 1n RAI 3.1.1-3, the staff asked the applicant

to justify the exclusion of the Westinghouse feedwater ring from the LRA. By letter dated July

22. 2004, the applicant responded that the internal feedwater distribution rings are within the

scope of license renewal, but are not subject to an'AMR because they do not support any

intended function of the'steam 'generators. tTh'ere are no design-bases or regulated events at

ANO-2 that rely on the SG feedwater ring to demonstrate successful mitigation and recovery

from the event. 'However, the applicant 'stated that it performs a visual inspection of the

feedwater distribution ring and J-nozzles'at least once every 5 years as part of the Steam'

Generator Integrity Program.

Although the applicant has not performed an AMR of the feedwater distribution ring and'Jnozzles, the staff finds the applicant's response acceptable because the applicant's periodic

inspection will detect aging effects of the feedwater distribution ring and J-nozzles. In addition,

the feedwater distribution ring in the replacement SGs'is designed to minimize potential thermral

fatigue which may cause cracking.

For Item 3.1.1-39, the applicant stated that loss'of material from erosion affecting SG

secondary manways and handholds is applicable to once-through' SGs and is not applicable to

the Westinghouse steam generators at ANO-2. However, the ANO-2 steam" generators do

have manways and handholds which may be'degraded from erosion.: In RAI 3.1.1-4, the staff

asked the applicant to justify why loss of material from erosion is not an applicable aging

mechanism for these'components in the ANO-2 steam 'generators.

By letter dated July 1, 2004, the applicant responded that Item 3.1.1-39 of Table 3.1.1

represents GALL Report Item IV.D2.1.10 (i.e., erosion of carbon steel manway covers).

Because Section IV.D2 of the GALL Report is-specific to once-through SGs and ANO-2 has -

recirculating SGs, this GALL Report line item is not applicable to ANO-2. The GALL Report

does not identify loss of material from erosion as an aging effect requiring management for

recirculating steam generators. This is consistent'with the results of the operating experience

review which did not identify erosion as an applicable aging mechanism for manway and

inspection port covers of recirculating steam generators. However, as identified in' LRA Table

3.1.2-5, page 3.1-98, loss of material is an AERM for the secondary manway and inspection

port covers (6 inch and 8 inch) exposed to internal treated water. Loss of mechanical closure

integrity is an AERM for secondary bolted closures, as indicated on page 3.1-104 of LRA Table

3.1.2-5. 'Localized leakage at bolted closures-may cause loss of material by erosion at ferritic

seating surfaces, which is managed by bolting and torquing activities'and the Inservice

Inspection Program. ' -

The staff finds the applicant's response-acceptable because LRA Table 31.2-5 does include

the aging management of the 3-in. and 6-in. inspection ports and the 8-in. handholds. Further,

the applicant has appropriate AMPs to manage the aging effect of these components.

Steam Generator Components in LRA Table'3.1.2-5 Requiring'Further Evaluation

LRA Table 3.1.2-5 summarizes the AMR of'SG components. Each SG component is identified

with associated intended function, material,'ervironment, aging effect, and AMP. The staff

reviewed LRA Table 3.1.2-5 to determine whether the applicant has demonstrated that the

effects of aging of the SG components will be adequately managed during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The following SG components in

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Table 3.1.2-5 need further evaluation or clarification.

In Table 3.1.2-5, the applicant identified the Steam Generator Integrity Program, described in

LRA Section B.1.25, to manage cracking in the antivibration bar end caps, peripheral retaining

rings, U-bend, and U-shaped retainer bars (see LRA, page 3.1-1 00), as well as stay rods, stayrod hex nuts, spacer pipes, peripheral backup bars, wrapper, and wrapper jacking screws (see

LRA page 3.1-106). In RAI 3.1.2.5-1, the staff asked the applicant.to (1) discuss how it

inspects these components and the frequency of inspection under the Steam Generator

Integrity Program, and (2) clarify whether the U-bend referred to on LRA page 3.1-1 00 is

applicable to the U-bend region of the tube or to the U-bend tube supports (e.g., peripheral

retaining rings and retainer bars).

By letter dated July 1, 2004, the applicant responded that the Steam Generator Integrity

Program includes visual inspection of the SG lower internals (tube support structures and tube

bundle, including the U-bend). This inspection is completed at least once every 5 years. This

inspection verifies loose parts and corrosion and other damage in this region. The SG upper

internals (moisture separators) require a thorough visual inspection once every 5 years. This

inspection looks for mechanical damage, corrosion, or other unusual conditions. The U-bend

referred to in LRA Table 3.1.2-5 on page 3.1-100 has a typographical error because the

reference is to the peripheral retaining rings and not to the tubes. The components on that

page should include the U-bend peripheral retaining ring and the U-shaped retainer bars. The

staff finds that the inspection of the secondary-side components is acceptable because the

applicant performs periodic visual inspections of the above components for potential

degradation.

The applicant identified LRA Section B.1.28, "System Walkdown Program," to manage loss of

material in an air environment for many of the SG components listed in LRA Table 3.1.2-5. In

RAI 3.1.2.5-3, the staff asked the applicant to (1) clarify how it documents the SG components

in the System Walkdown Program because the staff could not determine whether the SG

components are included in LRA Section B.1.28, and (2) discuss how it will inspect those SG

components that are not accessible for the inspection during system walkdown.

By letter dated July 1, 2004, the applicant responded that the primary program to manage loss

of material in an air environment in Table 3.1.2-5 is the Boric Acid Corrosion Prevention

Program. This is consistent with the GALL Report, which does not indicate the need for a

program to manage loss of material from general corrosion from external surfaces in an air

environment for systems that operate at temperatures above 100 0C (212 'F). Because SG

components operate at temperatures above 100 OC (212 'F), general corrosion in air is not an

applicable aging mechanism. For these components, loss of material resulting from corrosion

in air can be caused only by leakage. During system walkdowns, leakage can be detected from

both accessible and inaccessible components. For RCS components, the System Walkdown

Program is redundant with the Boric Acid Corrosion Prevention Program since both programs

rely on visual inspections to detect evidence of leakage. The staff finds the applicant's

response acceptable because the System Walkdown Program is a redundant and secondary

program to monitor the loss of material in steam generators in an air environment. The primary

program is the Boric Acid Corrosion Prevention Program, which also provides inspection of the

outer surface of steam generators.

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The applicant identified several aging mechanisms in the secondary side of the steam

generators that contribute to tube degradation. In RAI 3.1.2.5-4, the staff asked the applicant to

discuss the aging management of the loose parts in the steam generators. By letter dated July

1, 2004, the applicant responded that it performed the first inservice inspection for the

replacement steam generators during the spring 2002 refueling outage. -This inspection

identified one loose part in the secondary side of the steam generators, which was retrieved

during that outage. Measures are in place tormonitor for loose parts within the steam

generators and to prevent the introduction of foreign objects into the steam generators. ,The

applicant removes loose parts whenever possible as part of the foreign object search and

retrieval activity. In the unlikely event an object cannot be readily removed, it remains in the.

steam generator only if an evaluation is performed to determine that the object will not cause

unacceptable tube degradation. The applicant performs sludge lancing of the steam generators

at least once every 5 years. The applicant completes the secondary-side inspections in

accordance with operating procedures for the Steam Generator Integrity Program.

The staff finds the applicant's response acceptable because the applicant has procedures to

monitor and inspect the loose parts in the secondary side of the steam generators.

LRA Table 3.1.2-5, page 3.1-96, discusses the aging management of SG tube plugs. In RAI

3.1.2.5-5, the staff asked the applicant to discuss (1) the types and materials of tube plugs that

it has installed in the SG tubes, and (2) whether NRC Bulletin 89-01, and associated

supplements 1 and 2, IN 89-33, IN 89-65, and IN 94-87 are applicable to the tube plugs

installed in the steam generators. By letter dated July 1, 2004, the applicant responded that

there are two welded plugs (one at each end of the same tube) in steam generator B. These

Alloy-690 plugs were welded in place at the factory before shipment of the steam generator.

Steam generator A has no plugs. The NRC generic communications listed above describe

failures of certain installed SG tube plugs fabricated of Alloy-600 material from PWSCC.

Because the only plugs currently installed in the SG tubes are fabricated of Alloy-690 material

(which is highly resistant to PWSCC), the generic communications described in the RAI above

are not applicable to ANO-2. The staff agrees with the applicant that the previous NRC generic

communications regarding tube plugs do not apply to tube plugs in the steam generators.

On LRA page 3.1-96, the applicant identified the Water Chemistry Control Program as an AMP

to manage loss of material and cracking in the SG tubes. In RAI 3.1.2.5-6, the staff questioned

the industry guidelines used in the Water Chemistry Control Program. By letter dated July 1,

2004, the applicant responded that it based the Water Chemistry Control Program on the EPRI

guidelines in TR-1 05714, Revision 4, for primary water chemistry, and TR-1 02134, Revision 5,

for secondary water chemistry. The staff .is satisfied that the applicant is using the latest -

version of EPRI water chemistry reports.-;This demonstrates that the applicant has a procedure

to adopt the latest revision of the EPRI guidelines that it will use during the period of extended

operation... - .

Industry experience has shown that denting of tubes from corrosion of tube support plates is an

aging effect. The applicant did not identify tube denting as an aging effect. In RAI 3.1.2.5-7,

the staff asked the applicant to justify why it excluded denting as an aging effect for the SG

tubes.. By letter dated July 1, 2004, the applicant responded that the steam generators have

stainless steel tube support plates which are inherently resistant to the type of corrosion

(magnetite) leading to tube denting. Therefore, the SG tubes are not susceptible to denting.

The staff finds that the applicant's response is acceptable because industry experience for the

:3-139
stainless steel tube support plates has not shown extensive tube denting that would cause a

concern.

On LRA page 3.1-98, the applicant identified internal treated water as an environment for the

6-in. and 8-in. inspection port covers, but not for the 3-in. inspection port cover. Additionally,

the applicant identified the diaphragms in the 3-in. inspection port as a component for aging

management; however, it did not identify the diaphragm for the 6-in. or 8-in. inspection ports. In

RAI 3.1.2.5-8, the staff asked the applicant to clarify this discrepancy. By letter dated July 1,

2004, the applicant responded that the steam generator 3-in. inspection ports have Alloy 690

diaphragms which prevent the treated water from contacting the underside of the low-alloy steel

inspection port covers. The SG design does not include similar diaphragms for the 6-in. and

8-in. inspection ports. The staff finds that the applicant's clarification is acceptable and that it

properly manages the inspection port covers.

On LRA page 3.1-99, the applicant identified the Inservice Inspection Program to manage

cracking in the antivibration bars and tube support plates. In RAI 3.1.2.5-9, the staff questioned

the applicability of the Inservice Inspection Program to manage the aging effects of these

components. The staff asked the applicant to discuss the details of how these two components

will be inspected under the Steam Generator Integrity Program, including inspection scope,

frequency, and method.

By letter dated July 1, 2004, the applicant responded that it had inadvertently identified the

Inservice Inspection Program to manage cracking for the antivibration bars and tube support

plates. LRA Table 3.1.2-5, page 3.1-99, should identify only the Steam Generator Integrity and

Water Chemistry Control Programs as applicable aging management programs for these items.

The Steam Generator Integrity Program requires visual inspection of the SG lower internals,

including tube support structures and tube bundle. The applicant completes this inspection at

least once every 5 years. This inspection checks for loose parts and corrosion and other

damage in this region. The applicant performs an integrity assessment after each SG

inspection which addresses all known degradation mechanisms in the steam generator being

evaluated. The integrity assessment is performed in two parts, a condition monitoring

assessment and an operational assessment. The condition monitoring assessment ensures

that structural integrity was maintained during the previous operating cycle, while the

operational assessment ensures that structural integrity will continue to be maintained during

the upcoming operating interval. Each operational assessment addresses past operating

experience, current degradation mechanisms and locations, and other insights from previous

condition monitoring assessments. The staff finds that the applicant's clarification is acceptable

and that the appropriate AMPs manage the antivibration bars and tube support plates.

On LRA page 3.1-102, the applicant discussed the aging management for the feedwater inlet

nozzles. In RAI 3.1.2.5-11, the staff asked the applicant to discuss whether a flexitallic gasket

is used in the feedwater system because there have been cases where the pieces of broken

flexitallic gasket have fallen into the secondary side of the steam generators and caused tube

degradation. By letter dated July 1, 2004, the applicant responded that the SG feedwater inlet

nozzle is welded to the SG shell. As such, no flexitallic gasket is used at the feedwater inlet

nozzle to the steam generator. The staff finds that potential loose parts resulting from a failure

of the flexitallic gasket in the feedwater system is not of a concern at ANO-2.

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On LRA pages 3.1-102 and 3.1-103, the applicant identified the Inservice Inspection Program

to manage cracking in feedwater inlet nozzles, fe6dwater thermal sleeves, and flow-limiting

insert (integral flow restrictors). In RAI 3.1 .2.5-12, the staff asked the applicant to discuss the

inspection method and frequency for these components. By letter dated July 1,2004, the

applicant responded that it inspects the feedwater inlet nozzles in accordance with ASME Code,

Section Xl, Examination Category C-B. However, the applicant inadvertently identified the

Inservice Inspection Program as managing the'aging' effect of cracking for the feedwater' '

thermal sleeves and flow-limiting inserts (integral flow restrictors) on the steam generators.

Because these items are internal to the SG feedwater and steam nozzles, they are not

accessible for performance of inservice inspection2 For the nickel-based alloy feedwater

thermal sleeves and flow-limiting inserts, the applicant uses the WaterChemistry Control

Program alone to manage cracking and loss of material. The Water Chemistry Control

Program maintains the environment in the steam generators by controlling contaminants that

could lead to loss of riaterial and cracking.'; A review of operating experience identified no

failures caused by inadequate'chemistry control: The feedwater thermal sleeves and f 16wlimiting inserts are internal to SG feedwater and steam nozzles and, as such, do not have a

pressure boundary function.' -The Water Chemistry Control Program alone is sufficient to':

manage the aging effect of cracking for the'SG feedwater nozzle thermal sleeves and flowlimiting inserts.

The staff finds that the applicant's response is acceptable because the applicant identified the'

appropriate AMPs for the feedwater inlet nozzle, thermal sleeve, and flow-limiting inserts. The

applicant will inspect the feedwater inlet nozzle in accordance with ASME Code, Section Xl.

The thermal sleeve and flow limiting inserts are inaccessible for inspection; however, the'Water

Chemistry Control Program will manage the aging effects of these components. '

On LRA page 3.1-104, the applicant identified the Steam Generator Integrity Programrto'

manage cracking in key bracket and snubber lugs. In RAI 3.1.2.5-13, the staff questioned the

applicability of the Steam Generator Integrity Program to manage cracking in these

components." By letter dated July 1,2004, the applicant responded that it had inadvertently

identified the Steam Generator Integrity Program to manage cracking in these two components.

These components are located on the outer surface of the SG shell and interface with the SG

lateral support system. The Inservice Inspection Program manages cracking of these ' ' - components for the period of extended operation. The staff finds the applicant's clarification

acceptable because the applicant typically uses the Inservice Inspection Program', rather than _

the Steam Generator Integrity Program, to monitor the' key bracket and snubber lugs.

In RAI 3.1.2.5-14, the staff questioned why the applicant did not identify wall thinning or FAC

as an aging effect for the steam outlet nozzle,'as shown on LRA page'3.1-105, because this

aging effect is specified for the steam outlet nozzle in GALL IV D1.1-d. By letter dated July 1,

2004, the applicant responded that the nozzle in GALL' Item IV.D1.1 -d is carbon steel, whereas

the integral flow restrictors in the steam outlet nozzles at ANO-2 are fabricated with ' '' -;

nickel-based alloy. LRA page 3.1-103 identifies these flow restrictors, The applicant stated,

that nickel-based alloy material (Alloy-690) is not susceptible to FAC. Because of the integral

flow restrictors, the low-alloy steel of the steam outlet nozzles is not exposed to the highvelocity fluid that causes FAC. The staff finds that the applicant's response is acceptable

because the steam outlet restrictor/nozzle is fabricated with Alloy 690 material which is not

susceptible to wall thinning or FAC.

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J

On the basis of industry operating experience with this material and use of a water chemistry

control program consistent with the GALL Report, the staff finds the applicant's approach to

managing the aging effects for the SG components to be acceptable.

Aping Management Programs

For loss of material from the nickel-alloy SG tube plugs, U-tubes, divider plate, and tube plate

exposed to treated, borated water, the applicant credited the Primary and Secondary Water

Chemistry Control Program (AMP B.1.30.3). Section 3.0.3.1 of this SER documents the staff's

evaluation of this AMP. The staff concludes that the Primary and Secondary Water Chemistry

Control Program credited by the applicant for this line item is adequate.

During its review of Table 3.1.2-5 of the LRA, the staff identified that the SG inspection port

diaphragms had been associated with the wrong item from tables in the GALL Report. By letter

dated March 24, 2004, the applicant revised the associated note for this component type.

The staff finds that management of cracking in nickel-based alloy exposed to treated

water using the Water Chemistry Control Program, as determined by inservice inspection, is

acceptable.

Conclusion

On the basis of its audit and review, the staff concludes that the applicant has adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

steam generator components so that the component intended functions can 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.1.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the RV, internals, RCS, pressurizer, and SG components and component

types that are within the scope of license renewal and subject to an AMR will be adequately

managed so that the component 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 FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

RV, internals, RCS, pressurizer, and steam generator systems, as required by 10 CFR

54.21 (d).

3-142
3.2 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 system components and component groups associated with the

following systems:

* emergency core cooling system (ECCS)

* containment spray system

* 'containment cooling system - -

* containment penetrations system

* hydrogen control system

3.2.1 Summary of Technical Information In'the Application

In Section 3.2 of the LRA, the applicant provided the AMR results for the ESF system

'components and component types listed in LRA Tables 2.3.2-1 through 2.3.2-5. The applicant

also listed the materials, environments,'aging'effects requiring management, and AMPs

associated with each system. '

,ln Table 3.2.1, "Summary of the Aging Management Programs for Engineered Safety Features

"Evaluated in Chapter V of NUREG-1801," of the LRA, the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the engineered safety

tfeatures system components and component types. In Section 3.2.2.2 of the LRA, the

applicant provided information concerning Table 3.2.1 components for which further evaluation

is recommended by the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient information

:to demonstrate that the effects of agirig for the ESF system components that are within the

.scope of license renewal and subject to an AMR will be adequately managed so that the

component 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 performed an audit and review to confirm the applicant's claim that certain identified

AMRs are consistent with the staff-approved AMRs in the GALL Report. The staff did not

repeat its review of the matters described in the GALL Report. However, the staff did

Rdetermine that the material presented in the LRA was applicable and that the applicant had

; identified the appropriate GALL AMRs. The ANO-2 ANO-2 Audit and Review Report

documents the staff's onsite audit and review findings, which are summarized in Section 3.2.2.1

of this SER.

The staff also audited and reviewed those AMRs that are consistent with the GALL Report and'

for which further evaluation is recommended. The staff determined that the applicant's further

evaluations were consistent with the'acceptance criteria in Section 3.2.3.2 of the SRP-LR.

Section 3.2.2.2 of this SER summarizes the staff's audit and review findings.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. The review included evaluating whether the applicant had identified all plausible

3-143
aging effects, and that the aging effects listed were appropriate for the combination of materials

and environments specified. Section 3.2.2.3 of this SER documents the staff's review findings.

Finally, the staff reviewed the AMP summary descriptions in the FSAR Supplement to ensure

that they provide an adequate description of the programs credited with managing or monitoring

aging for the ESF systems components and component groups.

Table 3.2-1 below provides 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.

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

GALL Report

-CornonentAGroup ' "AgIng Effe' o f P MP In-GALL.'M 'G L -R In .;Staff Evaluat on'

~'-Mechan ~ ~ ReporV-, :. 4 .` 

Piping, fittings, and Cumulative fatigue TLAA, evaluated in TLAA - Metal Consistent with

valves in damage accordance with Fatigue GALL, which

emergency cooling 10 CFR 54.21(c)) recommends further

system evaluation (See (Item Number Section 3.2.2.2.1)

3.2.1-1)

Components in Loss of material Plant specific Containment Leak Consistent with

containment spray due to general Rate (B.1.6), Water GALL, which

(PWR only), corrosion Chemistry Control recommends further

standby gas (B.1.30) evaluation (See

treatment (BWR Section 3.2.2.2.2)

only), containment

isolation, and

emergency core

cooling systems (Item Number

3.2.1-3)

Components in Loss of material Plant specific Containment Leak Consistent with

containment spray due to pitting and Rate (B.1.6), Water GALL, which

(PWR only), crevice corrosion Chemistry Control recommends further

standby gas (B.1.30) evaluation (See

treatment (BWR Section 3.2.2.2.3)

only), containment

isolation, and

emergency core

cooling systems (Item Number

3.2.1-5)

Containment Loss of material Plant specific Containment Leak Consistent with

isolation valves and due to Rate (B.11.6), Water GALL, which

associated piping microbiologically Chemistry Control recommends further

(Item Number influenced corrosion (B.1.30) evaluation (See

3.2.1-6) (MIC) Section 3.2.2.2.4)

3-144
Component Group ''- '~AMPIng'fca'US&LRA--H 'S'taff Eviuatlon Agn Effc/ A1RnAL>.' - Mechanism: R or> a .'

High pressure Loss of material Plant specific Not Applicable to Consistent with

safety injection due to erosion ANO-2 GALL, which .

(charging) pump . recommends further

miniflow orifice evaluation (See

(Item Number . Section 3.2.2.2.6)

3.2.1-8) ;

Extemal surface of Loss of material Plant specific Containment Leak Consistent with

carbon steel due to general . Rate (B.1.6), Boric GALL, which -

components ' corrosion - .. -, Acid Corrosion recommends further

(Item Number ' ; Prevention (B.1.3) evaluation (See

3.2.1 -10) - , ' Section 3.2.2.2.2)

Piping and fittings Loss of fracture Thermal aging. Not Applicable to Consistent with

of CASS in toughness due to embrittlement of ANO-2 - GALL, which

emergency core thermal aging CASS recommends no

cooling system embrittlement further evaluation

(Item Number - > . (See Section,

3.2.1-11). . . .~ ~ - -*. 3.2.2.1).

Components Loss of material Openr-ycie cooling Service Water Consistent with'

serviced by open- due to general, water system Integrity '(B.1.24), GALL; which

cycle cooling pitting and crevice Water Chemistry recommends no

system corrosion, MIC, and '" ,ti: Control (8.1.30), further evaluation

(Item Number biofouling; buildup Heat Exchanger (See Section

3.2.1-12),_ of deposit due to . - Monitoring (8.1.12), 3.2.2.1)

biofouling ., - Periodic

.| . .Surveillance and

Preventive

Maintenance

(B.1.18)

Components Loss of material Closed-cycle Not Applicable to Consistent with

serviced by closed- due to general, cooling water ANO-2. GALL, which

cycle cooling pitting and crevice system recommends no

system corrosion further evaluation

(Item Number (See Section

3.2.1-13) . . 3.2.2.1)

Pumps, valves, Crack Initiation and Water chemistry Water Chemistry Consistent with

piping, and fittings, growth due to SCC Control (B.1.30) GALL, which

and tanks in , recommends no

containment spray further evaluation

and emergency - . . : - - , (See Section-:

core cooling ; . , 3.2.2.1) '

systems

(Item Number

3.2.1-15)

Carbon steel Loss of material Boric acid corrosion Boric Acid Consistent with

components due to boric acid Corrosion GALL, which

(item Number corrosion' . ... , Prevention (8. 1.3) recommends no1

3.2.1-17) - - - fu, frther evaluation

(See Section

3.2.2.1)

l 

of

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Component Goup- >i-G Aging Effec AMP In GALL -. i: A i ; RA ; af aiuatio

'. - * Mechanism e i - '. Repo -;-y - iClosure bolting in Loss of material Bolting integrity BoltingfTorquing Consistent with

high pressure or due to general Activities (B.1.2), GALL, which

high temperature corrosion; crack Boric Acid (B.1.3), recommends no

systems initiation and growth System Walkdown further evaluation

(Item Number due to cyclic (B.1.28) (See Section

3.2.1-18) loading and/or SCC 3.2.2.1)

The staff's review of the ANO-2 ESF system and associated components followed one of

several approaches. One approach, documented in Section 3.2.2.1 of this SER, involves the

staff's review of the AMR results for components in the ESF system that the applicant indicated

are consistent with the GALL Report and do not require further evaluation. Another approach,

documented in Section 3.2.2.2 of this SER, involves the staff's review of the AMR results for

components in the ESF system that the applicant indicated are consistent with the GALL Report

and for which further evaluation is recommended. A third approach, documented in Section

3.2.2.3 of this SER, involves the staff's technical review of the AMR results for components in

the ESF system that the applicant indicated are not consistent with the GALL Report, or are not

addressed in the GALL Report. Section 3.0.3 of this SER documents the staff's review of the

AMPs that are credited to manage or monitor aging effects of the ESF system components.

3.2.2.1 AMR Results That Are Consistent with the GALL Report

In Sections 3.2.2.1.1 through 3.2.2.1.5 of the LRA, the applicant identified the materials,

environments, and AERMs. The applicant identified the following programs that manage the

aging effects related to the ESF system components:

* Boric Acid Corrosion Prevention Program

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control Program

* System Walkdown Program

* Service Water Integrity Program

* Heat Exchanger Monitoring Program

* Bolting and Torquing Activities Program

* Containment Leak Rate Program

* Flow-Accelerated Corrosion Program

In Tables 3.2.2-1 through 3.2.2-5 of the LRA, the applicant provided a summary of the AMRs

for the ESF systems and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

In Tables 3.2.2-1 through 3.2.2-5 of the LRA, the applicant provided a summary of the AMRs

for the ESF systems and identified which AMRs it considered to be consistent with the GALL

Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency, and for which the GALL Report does not recommend further evaluation, the staff

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I
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 align 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. - . P . . I ;

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 determine 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 determine consistency

with the GALL Report. The staff determined that the identified exceptions to the GALL AMPs

had been reviewed and accepted by the staff. The staff also determined whether the AMP i

identified by the applicant was consistent with the AMP identified in the GALL Report, and

whether the-AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item differs from, but is consistent with,

the GALL Report for material, environment,'"and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some'system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to determine 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. *.,.L.*- .-

Note D indicates that the component for the'AMR line item differs from, but 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

determine consistency with the GALL Report. The staff determined whether'the AMR line item

of the different component was applicable-to' the component under review. The staff

determined 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 credits a different AMP. The staff audited these line items to

determine consistency with the GALL Report: -'The staff also determined whether the identified

AMP would manage the aging effect consistent with the AMP identified by 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 program

bases documents, which are available at the applicant's engineering office. On the basis of its

audit and review, the staff finds that the AMR results which the applicant claimed to be

'3-147
consistent with the GALL Report are in fact consistent with the AMRs in the GALL Report.

Therefore, the staff finds that the applicant identified the applicable aging effects which are

appropriate for the combination of materials and environments listed.

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the component intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Conclusion

The staff has evaluated the applicant's claim of consistency with the GALL Report. The staff

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing associated aging effects. On the basis of its review, the staff finds

that the applicant has demonstrated that the effects of aging for these components can be

adequately managed so that their intended functions can 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 Evaluation

is Recommended

Summary of Technical Information in the Application

In Section 3.2.2.2 of the LRA, the applicant provided further evaluation of aging management,

as recommended by the GALL Report, for ESF systems. The applicant provided information

concerning how it will manage the following aging effects:

* cumulative fatigue damage

* loss of material due to general corrosion

* local loss of material due to pitting and crevice corrosion

* local loss of material due to microbiologically influenced corrosion (MIC)

* changes in material properties due to elastomer degradation

* local loss of material due to erosion

* buildup of deposits due to corrosion

* quality assurance for aging management of nonsafety-related components

Staff Evaluation

For those component groups evaluated in the GALL Report, for which the applicant has claimed

consistency with GALL, and for which the GALL Report recommends further evaluation, the

staff reviewed the applicant's evaluation to determine whether it adequately addressed the

issues that were further evaluated. In addition, the staff audited the applicant's further

evaluations against the criteria contained in Section 3.2.2.2 of the SRP-LR. The ANO-2 ANO-2

Audit and Review Report documents the details of the staff's onsite audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

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3.2.2.2.1 Cumulative Fatigue Damage t

As stated in the SRP-LR, fatigue is a TLAA, as defined in 10 CFR 54.3. TLAAs are required to

be evaluated in accordance with 10 CFR 54.21 (c)(1). Section 4.3 of this SER documents the

staff's review of the applicant's evaluation of this TLAA. In performing this review, the staff

followed the guidance in Section 4.3 of the SRP-LR.

3.2.2.2.2 Loss of Material due to General Corrosion

In Section 3.2.2.2.2 of the LRA, the applicant addressed loss of material due to general

corrosion that could occur in the containment spray, containment isolation valves and

associated piping, and the external surfaces of carbon steel components.

Section 3.2.2.2.2 of the SRP-LR states that loss of material due to general corrosion could

occur in the containment spray, containment isolation valves and associated piping, and the

external surfaces of carbon steel components. The GALL Report recommends further

evaluation on a plant-specific basis to ensure that this aging effect is adequately managed.

The applicant stated that the Containment Leak Rate Program (AMP B.1.6) and the Water

Chemistry Control Program (AMP B.1.30.3) are credited with managing the aging effect of loss

of material due to general corrosion on external surfaces of carbon steel components in the

containment penetrations system. The applicant also stated that there are no carbon steel -

components in the containment spray system and the ECCS.

Sections 3.0.3.1 and 3.0.3.3.4 of this SER, respectively, document the staff's evaluation of the

Primary and Secondary Water Chemistry Control Program and the Containment Leak Rate.

Program. The staff concludes that the Primary and Secondary Water Chemistry Control

Program and the Containment Leak Rate Program credited by the applicant for this line item

are adequate. -

In Table 3.2.1, Item 3.2.1-10 of the LRA, the 'applicant also stated that the System Walkdown

Program (AMP B.1.28), the Boric Acid Corrosion Prevention Program (AMP B.1.3), and the

Containment Leak Rate Program (AMP B.1.6) manage loss of material due to general corrosion

on external surfaces of carbon steel components.- :

The staff reviewed the System Walkdown Program, the Boric Acid Corrosion Prevention

Program, and the Containment Leak Rate Program: Sections 3.0,3,3,9, 3.0.3.2.1,-and 3.0.3.1

of this SER, respectively, document the staff's evaluation of these programs. The staff

concludes that the System Walkdown Program,-the Boric Acid Corrosion Prevention Program,

and the Containment Leak Rate Program credited by the applicant for this line item are

adequate.

On the basis of its review of the Water Chemistry Control Program, the System Walkdown

Program, the Boric Acid Corrosion Prevention Program, and the Containment Leak Rate

Program, the staff finds that the applicant has appropriately evaluated the AMR results involving

management of the loss of material due to general corrosion, as recommended in the GALL

Report.

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-. A

3.2.2.2.3 Local Loss of Material due to Pitting and Crevice Corrosion

In Section 3.2.2.2.3 of the LRA, the applicant addressed local loss of material due to pitting and

crevice corrosion that could occur in the containment spray components, containment isolation

valves and associated piping, and the buried portion of the refueling water tank external

surface.

Section 3.2.2.2.3 of the SRP-LR states that local loss of material due to pitting and crevice

corrosion could occur in the containment spray components, containment isolation valves and

associated piping, and the buried portion of the refueling water tank external surface. The

GALL Report recommends further evaluation to ensure that this aging effect is adequately

managed.

The applicant stated that the refueling water storage tank is not buried, so it is not subject to

this aging mechanism. The applicant credited the Containment Leak Rate Program (AMP

B.1.13) and Water Chemistry Control Program (AMP B.1.30.3) with managing the aging effect

of loss of material due to pitting and crevice corrosion for the other components. The staff

evaluated and accepted the Primary and Secondary Water Chemistry Control Program and the

Containment Leak Rate Program. Section 3.0.3.1 and 3.0.3.3.4 of this SER, respectively,

document the staff's evaluation of these programs.

Subsection 3.2.2.2.3.2 of the SRP-LR recommends verification of the programs' effectiveness

and identifies one-time inspections as an acceptable method. Both programs include periodic

(rather than one-time) inspection of components, however, it does not appear that the

parameters monitored or locations inspected will allow the applicant to determine the presence

or extent of pitting and crevice corrosion.

By letter dated June 24, 2004, the staff asked the applicant, in RAI 3.2-11, to describe how the

presence or extent of pitting and crevice corrosion will be detected for ESF systems

components subject to this aging effect, and to provide the basis for assurance that periodic

inspections will provide an adequate sampling. In further discussions with the applicant, the

staff asked the applicant to confirm that planned activities will provide an appropriate sample for

each material and environment combination, or to provide for a review to confirm that each

material and environment combination subject to this aging effect has been adequately

sampled before the period of extended operation.

In its response, the applicant provided details of ESF systems' material and environment

groups that credit water chemistry control programs for local loss of material due to pitting and

crevice corrosion.- The applicant provided information on the following material and

environment combinations:

* carbon steel exposed to treated water greater than 132 OC (270 0F)

* carbon steel exposed to treated water

* Inconel exposed to treated, borated water

* stainless steel exposed to treated, borated water greater than 132 OC (270 OF)

* stainless steel exposed to treated, borated water

Based on its review, the staff finds the applicant's response to RAI 3.2-11 acceptable because

the applicant demonstrated that the AMR results involving management of the loss of material

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due to pitting and crevice corrosion have been appropriately evaluated, as recommended in the

GALL Report. Therefore, the staff considers in RAI 3.2-11 resolved.

3.2.2.2.4 Local Loss of Material due to Microbiologically Influenced Corrosion

In Section 3.2.2.2.4 of the LRA, the applicant addressed local loss of material due to MIC.

Section 3.2.2.2.4 of the SRP-LR states that local loss of material due to MIC could occur in

containment isolation valves and associated piping in systems that are not addressed in other

chapters of the GALL Report. The GALL Report recommends further evaluation to ensure that

this aging effect is adequately managed.

The applicant stated that the Containment Leak Rate Program (AMP B.1.6) and the water

chemistry control programs are credited with managing the aging effect of loss of material due

to MIC. Both programs include periodic (rather than one-time) inspection of components,

however, it does not appear that the parameters monitored will detect the presence or extent of

MIC. ;

By letter dated June 24, 2004, the staff asked the applicant, in RAI 3.2-12, to describe how it

will detect the presence or extent of MIC for piping and valve component types in the

containment penetrations system (see LRA Table 3.2.2-4).

In its response to RAI 3.2-12, the applicant stated that the majority of the containment

penetrations system component types in listed in LRA Table 3.2.2-4 are exposed to a treated

water environment, where sulfates are low (less than 150 parts per billion (ppb)). MIC is

unlikely to occur in treated water systems with low sulfates. The applicant credits the Water

Chemistry Control Program to minimize the potential for MIC by maintaining the system free of

contaminants. The Containment Leak Rate Program provides additional assurance that loss of

material due to MIC will be managed such that the containment penetrations system

components will continue to perform their intended functions.

In its response to RAI 3.2-12, the applicant further identified some stainless steel containment

penetrations system component types that are exposed to an untreated, borated water

environment such as part of the quench tank, the reactor drain tank vent and drainlines, and the

containment sump drainline. The applicant has confirmed the absence of MIC in the

containment sump by means of containment sump close-out inspections, which it performs

every refueling outage. Because these stainless steel component types in LRA Table 3.2.2-4

drain to the containment sump, the absence of MIC in the containment sump during inspections

provides evidence that these stainless steel components in LRA Table 3.2.2-4 do not have MIC.

Based on its review, the staff finds the applicant's response to RAI 3.2-12 acceptable because

the applicant demonstrated that the AMR results involving management of the loss of material

due to MIC have been appropriately evaluated, as recommended in the GALL Report.

Therefore, the staff considers RAI 3.2-12 resolved.

3.2.2.2.5 Changes in Material Properties due to Elastomer Degradation

The applicant stated that this issue applies to boiling-water reactors (BWRs) only; therefore, it is

not applicable to ANO-2. The staff concurs with the applicant's position.

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0

3.2.2.2.6 Local Loss of Material due to Erosion

In Section 3.2.2.2.6 of the LRA, the applicant addressed local loss of material due to erosion

that could occur in the HPSI miniflow orifice.

Section 3.2.2.2.6 of the SRP-LR states that local loss of material due to erosion could occur in

the HPSI pump miniflow orifice. This aging mechanism and its effect will apply only to pumps

that are normally used as charging pumps in the CVCS. The GALL Report recommends further

evaluation to ensure that this aging effect is adequately managed.

The applicant stated that the chemical and volume control charging pumps are used for the

RCS makeup at ANO-2, not the HPSI pumps. There are no orifices downstream of the

chemical and volume control charging pumps.

The staff finds that ANO-2 components are not subject to this aging effect.

On the basis that there are no orifices downstream of the chemical and volume control charging

pumps used for RCS makeup, the staff finds that this aging effect is not applicable to ANO-2.

3.2.2.2.7 Buildup of Deposits due to Corrosion

The applicant stated that this issue applies to BWRs only; therefore, it is not applicable to

ANO-2. The staff concurs with the applicant's position.

3.2.2.2.8 Quality Assurance for Aging Management of Nonsafety-Related Components

Section 3.0.4 of this SER provides a separate evaluation of the applicant's Quality Assurance

Program.

Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations

conducted in accordance with the GALL Report are consistent with the acceptance criteria in

Section 3.2.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging

can be adequately managed so that the intended function(s) can be maintained consistent with

the current licensing basis 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 the GALL Report

3.2.2.3.1 Emergency Core Cooling System

Summary of Technical Information in the Application

In Section 3.2.2.1.1 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the ECCS components:

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* Boric Acid Corrosion Prevention Program a:

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control Program

* - System Walkdown Program '

* Service Water Integrity Program

In Table 3.2.2-1 of the LRA, the applicant provided a summary of the AMRs for the ECCS

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The NRC staff reviewed the AMR of the ECCS component-material-environment-AERM

combinations that are not addressed in the GALL Report. These combinations are identified by

notes F through J in LRA Table 3.2.2-1, except for those which have past precedents. The staff

also reviewed those combinations in Table 3.2.2-1, with notes A through E, for which issues

were identified. The staff determined that the' applicant identified all applicable AERMs and

credited appropriate AMPs for managing the them. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions are adequate.

Aginq Effects

Table 2.3.2-1 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bearing housing, bolting, heat exchanger,(shell), heat exchanger (tubes), nozzle, orifice,

piping, pump casing, tank, thermowell, tubing, and valve.

For these component types, the applicant identified the materials, environments, and AERMS,

as specified below:

* Cast iron components exposed to a fresh raw water (internal) environment are subject

to the aging effects of fouling and loss of material.

* Cast iron components in air (external) environments are subject to loss of material.

* Carbon steel components (bolting) in air (external) environments are subject to loss of

material and loss of mechanical closure integrity.

* Stainless steel components in fresh raw water (internal) environments are subject to.

loss of material. - - - -

* Stainless steel components in fresh raw water (external), treated, borated water,

(internal), and treated, borated water greater than 132 'C (270 'F) (internal)

environments are subject to fouling, cracking and loss of material, and for fresh raw

water (internal), loss of material wear, as well.

* Inconel components in treated, borated water (internal) are subject to loss of material.

* Carbon steel with stainless steel cladding in air (external) and treated, borated water.

(internal) environments is subject to'loss of material.

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* Stainless steel components exposed to air (external) and nitrogen (internal)

environments experience no aging effects.

* Inconel components exposed to air (external) environments experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

review.

In LRA Table 3.2.1, Item 3.2.2-18, the applicant stated that this AMR item was not considered

to match the ANO-2 AMR results. The applicant stated that for closure bolting, the AERM is

loss of mechanical closure integrity, which includes a broader range of aging mechanisms than

those included in this line item (i.e., loss of material due to general corrosion; crack initiation

and growth due to cyclic loading and/or SCC). In RAI 3.2-1(1), (2), and (3), the staff requested

the applicant to (1) explain the extent to which AMR Item 3.2.1-18 does not match the ANO-2

results, (2) clarify whether the aging effect of loss of mechanical closure integrity includes loss

of material and cracking, and, specifically, what other aging effects/mechanisms are included in

the "broader range," and (3) discuss how it will manage each of the identified aging effects and

why the approach for managing these aging effects is adequate.

By letter dated April 6, 2004, the applicant stated that LRA Table 3.2-1, Item 3.2.1-18,

addresses closure bolting in high-pressure or high-temperature systems. Within the ESF

systems, the HPSI portion of the ECCS is a high-pressure system, but not a high-temperature

system. The only bolting in a high-temperature system is the bolting on components in the SG

blowdown and sampling penetrations in the containment penetrations system. In addition to

loss of material, loss of mechanical closure integrity is considered an AERM. Cracking is not

considered an AERM in the ESF systems because, at ANO-2, the potential for SCC of bolting in

non-Class 1 systems is minimized by using lower yield strength carbon steel bolting material

and limiting contaminants such as chlorides and sulfur in lubricants and sealant compounds.

The staff found that the applicant adequately addressed the question of why AMR Item 3.2.1-18

does not match the ANO-2 results by clarifying that the ESF closure bolting, which is in a hightemperature environment, is susceptible to loss of mechanical closure integrity due to loss of

preload, instead of crack initiation and growth due to cyclic loading and/or SCC. RAI 3.2.1(1) is,

therefore, closed.

The applicant stated that the words "broad range" refer to the fact that loss of mechanical

closure integrity is identified as an aging effect requiring management for bolting in two cases.

First, bolting in high-temperature systems and in applications subject to significant vibration is

subject to loss of mechanical closure integrity due to loss of preload, which is managed by the

Bolting and Torquing Activities Program. The same bolted closures may be subject to loss of

material, if they are carbon steel or wetted stainless steel. If so, the loss of material is managed

by the System Walkdown Program or the Boric Acid Corrosion Prevention Program. Second, in

the case of exposure to borated water leakage, loss of material may progress to such an extent

that it will affect the mechanical closure integrity. Thus, both the loss of material and the loss of

mechanical closure integrity are conservatively considered AERMs. In this case, both the loss

of material and the loss of mechanical closure integrity are managed by the Boric Acid

Corrosion Prevention and the System Walkdown Programs. Based on its review, the staff

found that the applicant adequately delineated the aging effects included under loss of

mechanical closure integrity, with a justifiable basis, and identified the associated AMPs to

manage these aging effects. RAI 3.2-1(2) and (3), therefore, are closed.

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I
f 1;

In Tables 3.2.2-1 and 3.2.2-2 of the LRA, for ECCS and containment spray systems, the

applicant identified loss of mechanical closure integrity as one of the aging effects (in addition

to loss of material) requiring management for carbon steel bolting in air (external)

environments. The Boric Acid Corrosion Prevention and the System Walkdown Programs are

credited for managing the aging effect. In RAI 3.2-2, the staff requested that the applicant

explain why it did not identify the Bolting and Torquing Activities Program as a required AMP.

By letter dated April 6, 2004, the applicant stated that both the ECCS and containment spray

system are exposed to air indoors with the potential for leaking borated water. Because of the

highly corrosive nature of boric acid on'carbon steel, borated water leakage could cause

significant loss of material from components of bolted closures. In this case, loss of mechanical

closure integrity is n' aging effect from excessive loss of material resulting from borated water

leakage, instead of from loss of preload. As a result, the Boric Acid Corrosion Prevention

Program and the System Walkdown Program, instead of the Bolting and Torquing Activities

Program, manage loss of material, and hence', loss of mechanical closure integrity. Based on

the above information and the fact that the bolted closures in the ECCS and the containment

spray system are not exposed to'high-temperature environments, the staff determined that the.

applicant adequately explained why it did not identify the Bolted and Torquing Activities

Program as a required AMP. RAI 3.2-2 is, therefore, closed.

In Table 3.2.2-1 of the LRA,- the applicant stated that the Water Chemistry Control Program is

used to manage cracking and loss of material for. stainless steel components in a treated, -

borated water greater than 132 0C (270 'F) (internal) environment. This AMP is also used to;

manage loss of material for stainless steel components in a treated, borated water (internal)

environment. In RAI 3.2-5, the staff requested that the applicant explain why a supplemental

inspection program is not needed to assess the effectiveness of the Water Chemistry Control

Program, as recommended by the GALL' Report. By letter dated April 6, 2004, the applicant.

stated that for the ESF systems, the GALL Report does not identify stainless steel components

among those certain cases requiring augmentation of the water chemistry program. The

applicant further stated the following:

NUREG-1801 does not include loss of material for stainless steel in any PWR

borated water environment, consistent with the minor significance of the aging

-reffect on this material. Operating history has demonstrated that the effect is

minor, even in stagnant water conditions. The response to a question from the

ANO-1 LRA review documents the results'of inspections of the ANO-1 control

rod drive mechanisms (CRDMs) which are also exposed to treated boratedwater. The response (ANO correspondence 1 CAN090002, item 3.3.2.8.2.2-2)

states, in part: "Loss of material by corrosion and pitting, and SCC of CRDM

pressure boundary items have not been observed at ANO-1 in visual inspectionsof drives during routine and corrective maintenance activities. In addition,

inspections at other B&W operating plants have found no indications in the motor

tube extensions." Thus, loss of material is not a significant aging effect for

stainless steel components in a typical PWR treated borated water (primary)

environment. This is not an unexpected result since the materials chosen forprimary systems were selected for their ability to withstand the borated water

environment. Although the loss of material is minor, the effect is possible. ANO2 has conservatively identified loss of material as an aging effect requiring

management for stainless steel in treated borated water. Since industry

experience has shown that primary water chemistry programs are effective in

3-.155
X

preventing (managing) loss of material, this program alone is sufficient to

manage the effect.

Based on the above, the staff finds the use of the chemistry program alone to be acceptable for

managing loss of material in stainless steel components, and the GALL recommendations of

augmenting the water chemistry program with a verification inspection are satisfied for the ESF

components. RAI 3.2-5 is, therefore, closed.

In Tables 3.2.2-1, 3.2.2-2, 3.2.2-3, and 3.2.2-5 of the LRA, the applicant stated that for stainless

steel bolting in air (external) environments, there is no applicable AERM. This presents a

different AMR result from the stainless steel bolting in Table 3.2.2-4 of the LRA for the

containment penetrations system, where loss of mechanical closure integrity is identified as an

aging effect under a similar environment. In RAI 3.2-9, the staff requested that the applicant

explain the apparent inconsistency in the above AMR results. By letter dated April 6, 2004, the

applicant stated that some of the bolting in the containment penetrations system (blowdown and

SG sampling) is exposed to high temperatures that could result in loss of preload and a loss of

mechanical closure integrity. The portions of the ECCS, containment spray, containment

cooling, and hydrogen control systems that are subject to AMR, on the other hand, are at low

temperatures and would not experience a loss of mechanical closure integrity. The staff

considered that the applicant has adequately explained why the stainless steel bolting is

susceptible to loss of mechanical closure integrity in the containment penetrations system, but

not in the other ESF systems. RAI 3.2-9 is, therefore, closed.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the ECCS component types not addressed by the GALL Report are consistent with industry

experience for these combinations of materials and environments. The staff did not identify any

omitted aging effects. Therefore, the staff finds that the applicant has identified the appropriate

aging effects for the materials and environments associated with the components in the ECCS.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The-staff also determined that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.2.2-1 identifies the following AMPs for managing the aging effects described

above for the ECCS.

* Boric Acid Corrosion Prevention Program (B.1.3)

* Periodic Surveillance and Preventive Maintenance Program (B.1.18)

* Service Water Integrity Program (B.1.24)

* System Walkdown Program (B.1.28)

* Water Chemistry Control Program (B.1.30)

Sections 3.0.3.2.1, 3.0.3.3.7, 3.0.3.2.7, 3.0.3.3.9, and 3.0.3.1 of this SER, respectively, present

the staff's detailed review of these AMPs.

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During its review, the staff determined that it needed additional information to complete its

review.

In LRA Table 3.2-1, Item 3.2.1-18, the applicant stated that the Bolting and Torquing Activities,

Boric Acid Corrosion Prevention, and System Walkdown Programs will manage loss of --

mechanical closure integrity. In RAI 3.2-1(4), the staff requested the applicant to demonstrate

that, with the combination of these AMPs, the aging effects associated with closure bolting will

be adequately managed, or managed in a manner equivalent to that described in GALL AMP

XI.M18, "Bolting Integrity." By letter dated April 6, 2004, the applicant stated that while theContainment Leak Rate, Boric Corrosion Prevention, and System Walkdown Programs will be

used to manage loss of material, the Bolting and Torquing Activities, Boric Acid Corrosion

Prevention, and System Walkdown Programs will be used to manage loss of mechanical

closure integrity. The applicant stated that visual inspections of bolting for loss of material and

loss of mechanical closure integrity, embodied in the Boric Acid Corrosion Prevention and

System Walkdown Programs, are adequate to assure that the closure bolting can perform its

intended function. Loss of material (and ultimately loss of mechanical closure integrity) for

external surfaces, such as a bolted closure, is a long-term aging effect that would be observed

well before aging progressed to the point of loss of intended function. In addition, the.

Containment Leak Rate Program verifies that leak rates of the penetrations are acceptable,

which proves that the closure bolting remains capable of performing its intended function. The

Bolting and Torquing Activities Program assures that proper torque values are applied to bolted

closures such that loss of mechanical closure integrity, as a result of loss of preload from high

temperatures, does not occur. The Bolting and Torquing Activities and the System Walkdown

Programs are plant-specific programs and are not intended to be comparable to GALL AMP

XI.M1 8, which stipulates the ISI requirements of the ASME Code, Section Xl. The ANO-2

Inservice Inspection Program for Class 1, 2, and 3 bolted closures includes these ISI

requirements. However, these inspection requirements are focused on identifying the aging

effect of cracking. Because cracking is not an AERM for non-Class 1 bolted closures, the;

applicant stated that it did not include the Inservice Inspection Program as an AMP for ESF

systems. Because the bolted closures under these systems include only ASME Code Class 2

and 3 closure bolting,the staff found that the applicant's response adequately addresses the:

staff's concem regarding the adequacy and sufficiency of the Bolting and Torquing Activities

and the System Walkdown Programs for the ANO-2 bolted closures. The applicant's response

also clarified, for closure bolting, the difference between these AMPs and the ANO-2 Inservice

Inspection Program, which primarily focuses on identifying the aging effect of cracking. Based

on the above, RAI 3.2-1(4) is closed.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI,%the staff finds that the applicant identified

appropriate AMPs for managing the aging effects of the ECCS component types not addressed

by the GALL Report. In addition, the staff finds the program descriptions in the UFSAR

Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the ECCS

components that are not addressed by the GALL Report, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

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10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21(d).

3.2.2.3.2 Containment Spray System

Summary of Technical Information in the Application

In Section 3.2.2.1.2 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the containment spray system components:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* Periodic Surveillance and Preventive Maintenance Program

* Service Water Integrity Program

* System Walkdown Program

* Water Chemistry Control Program

In Table 3.2.2-2 of the LRA, the applicant provided a summary of AMRs for the containment

spray system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The technical staff reviewed the AMR of the containment spray system component-materialenvironment-AERM combinations that are not addressed in the GALL Report. These

combinations are identified by notes F through J in LRA Table 3.2.2-2, except for those with

past precedents. The staff also reviewed those combinations in Table 3.2.2-2 identified by

notes A through E for which there were issues identified. The staff determined that the

applicant identified all applicable AERMs and has credited appropriate AMPs for managing

them. The staff also reviewed the applicable UFSAR Supplements for the AMPs to ensure that

the program descriptions are adequate.

Aging Effects

Table 2.3.2-2 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bolting, filter housing, heat exchanger (shell), heat exchanger (tubes), heat exchanger.

(tubesheet), heater housing, nozzle, orifice, piping, pump casing, tank, thermowell, tubing,

valve, and vortex breaker.

For these component types, the applicant identified the materials, environments, and AERMS,

as specified below:

* Carbon steel components (bolting) in air (external) and outdoor air (external)

environments are subject to loss of material and loss of mechanical closure integrity.

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I
* - Carbon steel components in air (external) and fresh raw water (internal) are subject to

loss of material. -

* Stainless steel components in fresh raw water (external) and treated, borated water

(internal) environments are subject to fouling and loss of material.

* Stainless steel components in fresh raw water (external) are subject to loss of materialwear.

* Stainless steel components in treated,' borated water greater than 132 0C (270 OF)

(internal) environments are subject to 'cracking and loss of material.

* Stainless steel components in untreated borated water (internal and external) are

subject to loss of material. -

* Ferritic stainless steel in fresh raw water (external) and treated borated water greater

than 132 'C (270 0F) (internal) environments are subject to fouling and loss of materialwear in fresh raw water (external).'

* Carbon steel components with stainless cladding in fresh raw water (external) are

subject to cracking, loss of material, and loss of material-wear.

* Cast stainless steel components in treated, borated water (internal) are subject to loss

of material. -

* - Stainless steel components exposed to air (external) and outdoor air (external)

environments, as well as cast stainless steel components exposed to air (external)

environments, experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

review. RAI 3.2-1(1), (2), and (3) requested the applicant to (1) explain the extent to which

AMR Item 3.2.1-18 does not match the ANO-2 results, (2) clarify whether the aging effect of

loss of mechanical closure integrity includes loss of material and cracking, and, specifically,

what other aging effects/mechanisms are included in the "broader range," and (3) discuss how

it will manage each of the identified aging effects and why the approach for managing the aging

effects is adequate. Section 3.2.2.4.1 of this SER provides the staff's discussion of this RAI

and its resolution by the applicant.

RAI 3.2-2 requested that the applicant explain why it did not credit the Bolting and Torquing

Activities Program as a required AMP for the aging effect of loss of mechanical closure

integrity. The staff also requested the applicant to provide a detailed description of the potential

aging effects included under loss of mechanical closure integrity, and to discuss how they will

be managed by the stated AMPs. Section 3.2.2.4.1 of this SER provides the staff's discussion

of this RAI and its resolution by the applicant.

In Table 3.2.2-2 of the LRA, the applicant stated it credits the Water Chemistry Control Program

to manage cracking and loss of material for stainless steel components in a treated, borated

water greater than 132 0C (270 OF) (internal) environments, and to manage loss of material for

stainless steel and cast stainless steel components in a treated, borated water (internal)

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environment. In RAI 3.2-6, the staff requested that the applicant explain why it does not need a

supplemental inspection program to assess the effectiveness of the Water Chemistry Control

Program. The staff's discussion of this RAI and its resolution by the applicant are similar to

those for RAI 3.2-5, which are provided in Section 3.2.2.4.1 of this SER.

RAI 3.2-9 requested that the applicant explain the differences in the AMR results for the

stainless steel bolting in air (external) environments, as provided in LRA Table 3.2.2-2 and

Table 3.2.2-4. Table 3.2.2-2 does not identify an AERM for stainless steel bolting in air

(external) environments, whereas Table 3.2.2-4 identifies, for containment penetrations system,

loss of mechanical closure integrity as an aging effect for the same bolting under a similar

environment. Section 3.2.2.4.1 of this SER provides the staff's discussion of this RAI and its

resolution by the applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the containment spray system component types not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the containment spray system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.2.2-2 identifies the following AMPs for managing the aging effects described

above for the containment spray system:

* Boric Acid Corrosion Prevention Program (B.1.3)

* Heat Exchanger Monitoring Program (B.1.12)

* Periodic Surveillance and Preventive Maintenance Program (B.1.18)

* Service Water Integrity Program(B.1.24)

* System Walkdown Program (B.1.28)

* Water Chemistry Control Program (B.1.30)

Sections 3.0.3.2.1, 3.0.3.3.3, 3.0.3.3.7, 3.0.3.2.7, 3.0.3.3.9, and 3.0.3.1 of this SER,

respectively, provide the staff's detailed review of these AMPs.

During its review, the staff determined that it needed additional information to complete its

review.

RAI 3.2-1(4) requested that the applicant explain why it did not identify the Bolting and Torquing

Activities Program as a required AMP for the containment spray system, and demonstrate that

the Boric Acid Corrosion Prevention, Bolting and Torquing Activities, and System Walkdown

Programs will adequately manage the aging effects associated with closure bolting, or will

manage these effects in a manner equivalent to that described in GALL AMP XI.M1 8. Section

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I
3.2.2.4.1 of this SER provides the staff's discussion of this RAI and its resolution by the

applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI-the staff finds that the applicant has

identified the appropriate AMPs for managing the aging effects of the containment spray.

system component types not addressed by the GALL Report. In addition, the staff finds the

program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the containment spray

system components that are not addressed by the GALL Report, 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 FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.2.2.3.3 Containment Cooling System

Summary of Technical Information in the Application

In Section 3.2.2.1.3 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the containment cooling system components:

* System Walkdown Program

* Periodic Surveillance and Preventive Maintenance Program

* Service Water Integrity Program :

In Table 3.2.2-3 of the LRA, the applicant provided a summary of AMRs for the containment

cooling system components and identified which AMRs it considered to be consistent with the

GALL Report. . ,

Staff Evaluation L -

The NRC staff reviewed the AMR of the containment cooling system component-materialenvironment-AERM combinations that are not addressed in the GALL Report. These

combinations are identified by notes F through J in LRA Table 3.2.2-3, except for those with

past precedents. The staff also reviewed those combinations in Table 3.2.2-3, identified by

notes A through E, for which there were issues identified. The staff determined that the

applicant identified all applicable AERMs and credited appropriate AMPs for managing them.

The staff also reviewed the applicable UFSAR Supplements for the AMPs to ensure that the

program descriptions are adequate. - - ,

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M

Aging Effects

Table 2.3.2-3 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The component types that do not rely on the GALL Report for AMR

include blower housing, bolting, cooling coil assembly, cooling coil housing, damper housing,

ductwork, piping and valve.

For these component types, the applicant identified the materials, environments, and AERMS,

as specified below:

* Carbon steel components in air (external and internal), condensation (external and

internal), and fresh raw water (internal) environments are subject to loss of material.

* Stainless steel components in condensation (external and internal) and fresh raw water

(internal) environments are subject to loss of material.

* Copper alloy components in condensation (external) and fresh raw water (internal)

environments are subject to fouling and loss of material, and for condensation (external)

environments, loss of material-wear, as well.

* Stainless steel components in air (external and internal) environments experience no

aging effects.

During its review, the staff determined that it needed additional information to complete its

review.

RAI 3.2-1(1), (2), and (3) requested the applicant to (1) explain the extent to which AMR Item

3.2.1-18 does not match the ANO-2 results, (2) clarify whether the aging effect of loss of

mechanical closure integrity includes loss of material and cracking, and, specifically, what other

aging effects/mechanisms are included in the "broader range," and (3) discuss how it will

manage each of the identified aging effects and why the approach for managing the aging

effects is adequate. Section 3.2.2.4.1 of this SER provides the staff's discussion of this RAI

and its resolution by the applicant.

In Table 3.2.2-3 of the LRA, the applicant stated that loss of material is identified as the AERM

for carbon steel bolting in air (external) and condensation (external) environments, and

stainless steel bolting in condensation (external) environments. In RAI 3.2-3, the staff

requested that the applicant explain why it did not identify loss of mechanical closure integrity

as an AERM for the bolting, and how it would be managed if identified. By letter dated April 6,

2004, the applicant stated that it did identify loss of mechanical closure integrity as an AERM for

bolting in two cases. First, bolting in high-temperature systems and in applications subject to

significant vibration is also subject to loss of mechanical closure integrity caused by loss of

preload, which is managed by the Bolting and Torquing Activities Program. The same bolted

closures may be subject to loss of material if they are carbon steel or wetted stainless steel,

and are managed by the System Walkdown or the Boric Acid Corrosion Prevention Programs.

Second, in case of exposure to borated water leakage, loss of material may progress to such

an extent that it will affect the mechanical closure integrity. In this case, the applicant

conservatively considers both the loss of material and the loss of mechanical closure integrity

as AERMs, which are managed by the Boric Acid Corrosion Prevention and the System

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Walkdown Programs.

Based on the above, the applicant did not identify the loss of mechanical closure integrity as an

AERM for bolting in the containment cooling system because the containment cooling system is

not a high-temperature system, it is not subject to significant vibration, and it does not contain

borated water. The staff found that the applicant adequately delineated the aging effects -

covered under loss of mechanical closure integrity, and explained why it did not identify them as

AERMs for the bolting in the containment cooling system. RAI 3.2-3 is, therefore, closed.

RAI 3.2-9 requested that the applicant explain the differences in the AMR results for the

stainless steel bolting in air (external) environments, as provided in LRA Table 3.2.2-3 and

Table 3.2.2-4. Table 3.2.2-3 does not identify an AERM for stainless steel bolting in air

(external) environments, whereas Table 3.2.2-4 identifies, for containment penetrations system,

loss of mechanical closure integrity as an aging effect for the same bolting under a similar

environment. Section 3.2.2.4.1 of this SER provides the staff's discussion of this RAI and its

resolution by the applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the containment cooling system component types not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the containment cooling system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.2.2-3 identifies the following AMPs for managing the aging effects described

above for the containment cooling system: .-,, ;

* Periodic Surveillance and Preventive Maintenance Program (B.1.1 8): ,;

* Service Water Integrity Program (B.1.24) -

* System Walkdown Program (B.1.28)';-. -,

Sections 3.0.3.3.7, 3.0.3.2.7, and 3.0.3.3.9 of this SER, respectively, present the staff's detailed

review of these AMPs.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the containment

cooling system component types not addressed by the GALL Report. In addition, the staff finds

the program descriptions in the UFSAR Supplement acceptable.

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M

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the containment

cooling system components that are not addressed by the GALL Report, 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 FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21(d).

3.2.2.3.4 Containment Penetration System

Summary of Technical Information in the ApDlication

In Section 3.2.2.1.4 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the containment penetrations system components:

* Boric Acid Corrosion Prevention Program

* Bolting and Torquing Activities Program

* Containment Leak Rate Program

* Flow-Accelerated Corrosion Program

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control Program

In Table 3.2.2-4 of the LRA, the applicant provided a summary of AMRs for the containment

penetrations system components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation

The NRC staff reviewed the AMR of the containment penetrations system component-materialenvironment-AERM combinations that are not addressed in the GALL Report. These

combinations are identified by notes F through J in LRA Table 3.2.2-4,; except for those with

past precedents. The staff also reviewed those combinations in Table 3.2.2-4, identified by

notes A through E, for which issues were identified. The staff determined that the applicant

identified all applicable AERMs and credited appropriate AMPs for managing the AERMs. The

staff also reviewed the applicable UFSAR Supplements for the AMPs to ensure that the

program descriptions adequately describe the AMPs.

Aging Effects

Table 2.3.2-4 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bolting, flex hose, piping, tubing, and valve.

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For these component types, the applicant identifies the materials, environments, and AERMS,

as specified below: F.

* Carbon steel bolting in air (external), condensation (external), and untreated borated

water, (external) environments is subject to loss of material, and for air (external)

environments, loss of mechanical closure integrity, as well.

* -Carbon steel components are subject to loss of material when exposed to air (external

and internal), condensation (external), treated water (internal), and treated water greater

than 132 0C> (270 OF) (internal) environments.

* Stainless steel bolting in air (external) environment is subject to loss of mechanical

closure integrity.

* Stainless steel components in untreated, borated water (internal) and treated water

greater than 132 0C (270 0F) (internal) environments are subject to cracking and loss of

material.

* Elastomer components in air (external) and nitrogen (internal) environments are subject

to cracking and change in material properties.

* Carbon steel components in nitrogen environments experience no aging effects.

* Stainless steel components in air (external and internal), concrete, and nitrogen

environments experience no aging effects.

* Copper alloy components in air (external) and nitrogen (internal) environments

experience no aging effects.

During its review, the staff determined that it needed additional information.

RAI 3.2-1(1), (2), and (3) requested the applicant to (1) explain the extent to which AMR Item

3.2.1-18 does not match the ANO-2 results, (2) clarify whether the aging effect of loss of

mechanical closure integrity includes loss of material and cracking, and, specifically, what other

aging effects/mechanisms are included in the Bbroader range," and (3) discuss how it will

manage each of the identified aging effects and why the approach for managing the aging

effects is adequate. Section 3.2.2.4.1 of this SER provides the staff's discussion of this RAI

and its resolution by the applicant.

In Table 3.2.2-4 of the LRA, the applicant stated that it identified loss of mechanical closure

integrity as the AERM for carbon steel and stainless steel bolting, all in air (external)

environments. The applicant credits the Bolting and Torquing Activities Program as an AMP.

In view of the discussion provided in AMR Item 3.2.1-18, the staff requested, in RAI 3.2-4, that

the applicant explain why it did not also credit the System Walkdown Program as an AMP. By

letter dated April 6, 2004, the applicant stated that loss of mechanical closure integrity is an

AERM for bolting that can experience a loss of preload caused by exposure to high

temperatures, significant vibration, or significant loss of material from borated water-leakage.

For the containment penetrations system, the Bolting and Torquing Activities Program manages

loss of mechanical closure integrity'because the bolting in question is exposed to high:'

'3-165
in

temperatures. This program manages aging through the application of proper torque values to

the bolting. The applicant uses the Containment Leak Rate Program, on the other hand, to

manage the aging effect of loss of material for carbon steel bolting without reliance upon

system walkdowns. The staff found the applicant's response to be adequate in providing the

basis of how it will manage the aging effects of loss of material and/or loss of mechanical

closure integrity. RAI 3.2-4 is, therefore, closed.

In Table 3.2.2-4 of the LRA, the applicant stated that it credits the Water Chemistry Control

Program to manage cracking and loss of material for the stainless steel valve in a treated,

borated water greater than 132 'C (270 OF) (internal) environments. In RAI 3.2-7, the staff

requested that the applicant explain why it does not need a supplemental inspection program to

assess the effectiveness of the Water Chemistry Control Program. The staff's discussion of

this RAI and its resolution by the applicant is similar to that for RAI 3.2-5, which is provided in

Section 3.2.2.4.1 of this SER.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the containment penetrations system component types not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore; the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the containment penetrations system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.2.2-4 identifies the following AMPs for managing the aging effects described

above for the containment penetrations system.

* Bolting and Torquing Activities Program (B.1.2)

* Boric Acid Corrosion Prevention Program (B.1.3)

* Containment Leak Rate Program (B.1.6)

* Flow-Accelerated Corrosion Program (B.1.11)

* Periodic Surveillance and Preventive Maintenance Program (B.1.18)

* Water Chemistry Control Program (B.1.30)

Sections 3.0.3.3.2, 3.0.3.2.1, 3.0.3.1,3.0.3.1, 3.0.3.3.7, and 3.0.3.1 of this SER, respectively,

provide the staff's detailed review of these AMPs.

During its review, the staff determined that it needed additional information to complete its

review.

RAI 3.2-1(4) requested the applicant to demonstrate that the Boric Acid Corrosion Prevention,

Bolting and Torquing Activities, and System Walkdown Programs will adequately manage the

aging effects associated with closure bolting, or will manage them in a manner equivalent to

3-166
that described in GALL AMP XI.M18. Section 3.2.2.4.1 of this SER provides the staff's

discussion of this RAI and its resolution by the applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the containment penetrations

system component types not addressed by the GALL Report. In addition, the staff finds the

program descriptions in the UFSAR supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the containment

penetration system components that are not addressed by the GALL Report, 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 FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as,.

required by 10 CFR 54.21 (d).

3.2.2.3.5 Hydrogen Control System

Summary of Technical Information in the ADplication

In Section 3.2.2.1.5 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

AERMs for the hydrogen control system components:

* System Walkdown Program

* Service Water Integrity Program

In Table 3.2.2-5 of the LRA, the applicant provided a summary of AMRs for the hydrogen

control system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation :, ;

The NRC staff reviewed the AMR of the hydrogen control system component-materialenvironment-AERM combinations that are not addressed in the GALL Report. These

combinations are identified by notes F through J in LRA Table 3.2.2-5, except for those with

past precedents. The staff also reviewed those combinations in Table 3.2.2-5, identified by

notes A through E, for which issues were identified. The staff confirmed that the applicant has

identified all applicable AERMs and has credited appropriate AMPs for managing the AERMs.

The staff also reviewed the applicable UFSAR supplements for the AMPs to ensure that the

program descriptions are adequate. .:

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--

Aging Effects

Table 2.3.2-5 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bolting, filter housing, heat exchanger (shell and tubes), orifice, piping, pump casing,

tubing, and valve.

For these component types, the applicant identified the materials, environments, and AERMs,

as specified below:

* Carbon steel components in air (external) environments are subject to loss of material.

* Stainless steel components in condensation (external) and fresh raw water (internal) are

subject to loss of material.

* Stainless steel components in fresh raw water (external) are subject to fouling, loss of

material, and loss of material-wear.

* Stainless steel components in air (external and internal) and condensation (internal)

environments experience no aging effects.

During its review, the staff determined that it needed additional information.

RAI 3.2-1(1), (2), and (3) requested the applicant to (1) explain the extent to which AMR Item

3.2.1-18 does not match the ANO-2 results (2) clarify whether the aging effect of loss of

mechanical closure integrity includes loss of material and cracking, and, specifically, what other

aging effects/mechanisms are included in the "broader range," and (3) discuss how it will

manage each of the identified aging effects and why the approach for managing the aging

effects is adequate. Section 3.2.2.4.1 presents the staff's discussion of this RAI and its

resolution by the applicant.

In Table 3.2.2-5 of the LRA, the applicant stated that it identified loss of material as an AERM

for the carbon steel bolting in air (external) environments. In RAI 3.2-8, the staff requested that

the applicant explain why it did not specify loss of mechanical closure integrity and its

associated AMPs for the bolting. By letter dated April 6, 2004, the applicant stated that the

hydrogen control system internal environment is air, and not borated water, as in the other

systems. As a result, there is very little potential for any carbon steel bolting in the system to be

exposed to borated water leakage that would result in loss of mechanical closure integrity. In

addition, the system is not subject to elevated temperatures or significant vibration. The staff

considered the applicant's response to be adequate in explaining why it did not identify loss of

mechanical closure integrity as an AERM for the bolting in this system. RAI 3.2-8 is, therefore,

closed.

RAI 3.2-9 requested that the applicant explain the differences in the AMR results for the

stainless steel bolting in air (external) environments, as provided in LRA Tables 3.2.2-5 and

3.2.2-4. Table 3.2.2-5 does not identify an AERM for stainless steel bolting in air (extemal)

environments, whereas Table 3.2.2-4 identifies, for containment penetrations system, loss of

mechanical closure integrity as an aging effect for the same bolting under a similar

environment. Section 3.2.2.4.1 of this SER presents the staff's discussion of this RAI and its

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resolution by the applicant.

In Table 3.2.2-5 of the LRA, the applicant stated it did not identify any aging effects for the

stainless steel heat exchanger (tubes) in a condensation (internal) environment. Because

industry experience indicates that stainless steel may be susceptible to the aging effect of loss

of material when exposed to condensation with alternating wetting and drying, the staff

requested, in RAI 3.2-10, that the applicant explain why it did not identify an aging effect for the

component. By letter dated April 6, 2004, the applicant stated that for ANO-2, it identified loss

of material as an aging effect for stainless steel, with condensation as an environment, when

there is a potential for concentrating chemical species through repeated alternating wet and dry

conditions. Conservatively, the applicant identified condensation as an internal environment in

the hydrogen control system sample coolers, even though the coolers are only operated

intermittently for short periods of time. The hydrogen control system normally has no flow

through it, and, as a result, would not contain significant amounts of aggressive chemicals.

Thus, there is minimal possibility of concentrating chemicals, and loss of material is not an

aging effect requiring management. The staff considered the applicant's response to be

adequate in explaining why it did not identify any aging effects for the stainless steel,

components in the specific condensation (internal) environment. RAI 3.2-10 is, therefore,;

closed.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the hydrogen control system component types not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the hydrogen control system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement contains an adequate

description of the program.

LRA Table 3.2.2-5 identifies the following AMPs for managing the aging effects described

above for the hydrogen control system.

* Service Water Integrity Program (B.1.24)

* System Walkdown Program (B.1.28)

Sections 3.0.3.2.7 and 3.0.3.3.9 of this SER, respectively, present the staff's detailed review of

these AMPs.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified the appropriate AMPs for managing the aging effects of the hydrogen

control system component types not addressed by the GALL Report. In addition, the staff finds

the program descriptions in the UFSAR Supplement acceptable.

-3-1 69
M

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the hydrogen control

system components that are not addressed by the GALL Report, 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 FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.2.3 Conclusion

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the aging effects associated with the engineered safety feature systems components will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

engineered safety feature systems, as required by 10 CFR 54.21 (d).

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3.3 Auxiliarv Svstems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary system components and component groups associated with the following systems:

* spent fuel pool system

* water suppression fire protection systerm: -;

* emergency diesel generator system'

* alternate ac diesel generator system

* chemical and volume control system

* Halon fire protection and reactor coolant pumrp motor oil leakage collection system

* fuel oil system

* service water system

* auxiliary building ventilation system

* control room ventilation system

* miscellaneous systems in scope of 10CFR 54.4(a)(2)

3.3.1 Summary of Technical Information in the Application

In Section 3.3 of the LRA, the applicant provided the results of the AMR of the auxiliary systems

components and component types listed in Tables 2.3.3-1 through 2.3.3-11 of the LRA. The

applicant also listed the materials, environments; aging effects requiring management, and

aging management programs associated with each system.

In Table 3.3.1, "Surmmary of the Aging Management Programs for the Auxiliary Systems

Evaluated in Chapter VII of NUREG-1 801," of the LRA, the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the auxiliary systems

components and component types. In Section 3.3.2.2 of the LRA, the applicant provided

information concerning Table 3.3.1 components for which the GALL Report recommends

further evaluation.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determineif the applicant provided sufficient information

to demonstrate that the effects of aging for the reactor system components that are within the

scope of license renewal and subject to an AMR will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff performed an audit 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 determine that the material presented in the LRA was

applicable and that the applicant had identified the appropriate GALL AMPs. Section 3.0.3 of

this SER documents the staff's evaluations of the AMPs. The audit report issued on August 19,

2004, and summarized in Section 3.3.2.1 of this SER, documents the staff's audit findings.

The staff also performed an audit of those AMRs that were consistent with the GALL Report

and for which further evaluation is recommended. During the audit, the staff determined that

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the applicant's additional evaluations were consistent with the acceptance criteria in Section

3.3.2.2 of the SRP-LR. The staff's audit findings are documented in the audit report and

summarized in Section 3.3.2.2 of this SER.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. The review included evaluating whether the applicant had identified all plausible

aging effects and whether the aging effects listed were appropriate for the combination of

materials and environments specified. Section 3.3.2.3 of this SER documents the staff's review

findings.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

reactor system components.

Table 3.3-1 below summarizes the staff's evaluation of the 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 System Components in the GALL Report

Corproneni Group' Agig gEffct( - AM: - -- AMP In LRA'. .'- iva f

Mechanism ._ . ; . ;Rep- R; i t . -

Components in Loss of material Water chemistry Water Chemistry Consistent with

spent fuel pool due to general, and one-time Control (B.1.30) GALL, which

cooling and cleanup pitting, and crevice inspection recommends further

(Item Number corrosion evaluation (See

3.3.1-1) Section 3.3.2.2.1)

Linings in spent fuel Hardening, cracking Plant specific Periodic Consistent with

pool cooling and and loss of strength Surveillance and GALL, which

cleanup system; due to elastomer Preventive recommends further

seals and collars in degradation; loss of Maintenance evaluation (See

ventilation systems material due to (B.1.18) Section 3.3.2.2.2)

(Item Number wear

3.3.1-2)

Components in load Cumulative fatigue TLAA, evaluated in Consistent with

handling, chemical damage accordances with GALL, which

and volume control 10 CFR 54.21 (c) recommends further

system (PWR), and evaluation (See

reactor water Section 3.3.2.2.3)

cleanup and

shutdown cooling

systems (older

BWR)

(Item Number

3.3.1-3) .

It

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I
ZImponent'Group- ''`Agig Effectl i- - in BALL i-, .; -A- i LRA .*. Staff EvaIuation

- ~*-V '.- eMchan sm: e'po' reo- t: ;.

Heat exchangers in Crack initiation and Plant specific Water Chemistry Consistent with

reactor water growth due to SCC Control (B.1.30) GALL, which

cleanup system - or cracking recommends further

(BWR); high evaluation (See '

pressure pumps in Section 3.3.2.2.4)

chemical and

volume control

system (PWR) l

(Item Number

3.3.1.4) ' '' '

Components in Loss of material Plant specific Fire Protection Consistent with

ventilation systems, due to general, (8.1.10), System GALL, which

diesel fuel oil pitting, and crevice . Walkdown (B.1.28), recommends further

system,' and corrosion, and MIC Wall Thinning evaluation (See

emergency diesel Monitoring (B.1.29), Section 3.3.2.2.5)

generator systems; and Periodic

external surfaces of Surveillance and

carbon steel Preventive

components Maintenance

(Item Number (.B.1.18)

3.3.1-5) ' ' '_. :

Components in' Loss of material One-time Inspection Periodic Consistent with

reactor coolant due to galvanic, Surveillance and GALL, which

pump oil collect general, pitting, and Preventive recommends further

system of fire crevice corrosion Maintenance evaluation (See

protection (8.1.18) Section 3.3.2.2.6)

(Item Number

3.3.1-6) ' . . . . .

Diesel fuel oil tanks Loss of material Fuel oil chemistry Diesel Fuel Consistent with

in diesel fuel oil due to general, and one-time Monitoring (B.1.7), GALL, which:

system and ' pitting, and crevice Inspection Periodic recommends further

emergency diesel corrosion, MIC, and Surveillance and evaluation (See '

generator system biofouling " Preventive Section 3.3.2.2.7)

(Item Number ,'! , Maintenance

3.3.1-7) ' (B.1.18), and

Service Water

Integrity (B.1.24)

Heat exchangers in Crack initiation and Water chemistry Water Chemistry Consistent with

chemical and growth due to SCC and a plant-specific Control (B.1.30) GALL, which'

volume control and cyclic loading verification program recommends further

system evaluation (See-

(Item Number - Section 3.3.2.2.9)

3.3.1-9)

Neutron absorbing' Reduction of Plant specific Not Applicable to Consistent with

sheets in spent fuel neutron absorbing ANO-2 ' GALL, which'

storage racks capacity and loss of recommends further

(Item Number material due to ' ' . - evaluation (See

3.3.1-10) general corrosion Section 3.3.2.2.10)

(Boral, boron steel)

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Comp.nen Group: Aging Effec AMP in GA '. ' AMP in LRA-,- Staff Evaluaton'

' ,'- Mechanism.' .- Repor;t i-. . of.* . .

New fuel rack Loss of material Structures Structures Consistent with

assembly due to general, monitoring Monitoring - GALL, which

(Item Number pitting, and crevice Structures (B.1.27) recommends no

3.3.1-11) corrosion further evaluation

(See Section

3.3.2.1)

Neutron absorbing Reduction of Boraflex monitoring Not Applicable to Consistent with

sheets in spent fuel neutron absorbing ANO-2 GALL, which

storage racks capacity due to recommends no

(Item Number Boraflex further evaluation

3.3.1-12) degradation (See Section

3.3.2.1)

Spent fuel storage Crack initiation and Water chemistry Water Chemistry Consistent with

racks and valves in growth due to stress Control (B.1.30) GALL, which

spent fuel pool corrosion cracking recommends no

cooling and cleanup further evaluation

(Item Number (See Section

3.3.1-13) 3.3.2.1)

Closure bolting and Loss of material Boric acid corrosion Boron Acid Consistent with

external surfaces of due to boric acid Corrosion GALL, which

carbon steel and corrosion Prevention (B.1.3) recommends no

low-alloy steel further evaluation

components (See Section

(Item Number 3.3.2.1)

3.3.1-14)

Components in or Loss of material Closed-cycle Water Chemistry Consistent with

serviced by closed- due to general, cooling water Control (B.1.30) GALL, which

cycle cooling water pitting, and crevice system recommends no

system corrosion, and MIC further evaluation

(Item Number (See Section

3.3.1-15) 3.3.2.1)

Cranes including Loss of material Overhead heavy Structures Consistent with

bridge and trolleys due to general load and light load Monitoring - GALL, which

and rail system in corrosion and wear handling system Structures recommends no

load handling Monitoring (B.1.27) further evaluation

system (See Section

(Item Number 3.3.2.1)

3.3.1-16)

Components in or Loss of material Open-cycle cooling Water Chemistry Consistent with

serviced by open- due to general, water system Control (B.1.30) GALL, which

cycles cooling water pitting, crevice, and recommends no

systems galvanic corrosion, further evaluation

(Item Number MIC, and biofouling; (See Section

3.3.1-17) buildup of deposit 3.3.2.1)

due to biofouling

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I
-Coipbneit Group' sAging Effec ; ~--_ AP 1in GALL *;'AMP ink LA Sta EvaluationIi .g*oup,Z-, AM19 d: i r l'ti. ._. . , _ i, d ~ < -,-- ." .,'7 -11"' -7 .' 4'R 

Buried piping and Loss of material Buried piping and Buried Piping Consistent with

fittings due to general,. tanks surveillance Inspection (B.1.4) GALL, which

(Item Number pitting, and crevice recommends no

3.3.1-18) - corrosion, and MIC or further evaluation

(See Section

3.3.2.1)

Buried piping and Consistent with

tanks inspection GALL, which

recommends - .further evaluation

._ __ .(3.32.2.11)

Components In Loss of material Compressed air Consistent with

compressed air due to general and monitoring GALL, which.

system t pitting corrosion recommends no

(Item Number further evaluation

3.3.1-19) . (See Section

. . * _ 3.32.1)

Components (doors Loss of material Fire protection Fire Protection Consistent with

and barrier due to wear; (B.1.10) GALL, which

penetration seals) hardening and . i, - recommends'no

and concrete shrinkage due to - further evaluation

structures in fire weathering (See Section

protection 3.32.1)

(Item Number

3.3.1-20) . . ; _. : .

Components In Loss of material Fire waier system Fire Protection : Consistent with.

water-based fire due to general, .. , (B.1.10) GALL, which

protection pitting, crevice, and recommends no

(Item Number . galvanic corrosion , . further evaluation

3.3.1-21) MIC, and biofouling .,. . . (See Section

. . K . . ___ 3.3.2.1)

Components in Loss of material Fire protection and Diesel Fuel Consistent with

diesel fire system due to galvanic, fuel oil chemistry Monitoring (B.1.7) GALL, which

(Item Number general, pitting, and . and Fire Protection recommends no

3.3.1-22) crevice corrosion (B.1.10) further evaluation

.. . (See Section

.3.3.2.1)

Tanks In diesel fuel Loss of material .. Aboveground . System Walkdown Consistent with

oil system' due to general, carbon steel tanks (B.1.28) GALL, which

(Item Number pitting, and crevice - recommends no

3.3.1-23) corrosion . further evaluation

(See Section . 3.3.2.1)

Closure bolting Loss of material Bolting integrity Bolting and Consistent with

(Item Number due to general . Torquing Activities GALL- which

3.3.1-24) corrosion; crack (B.1.2) recommends no

initiation and growth further evaluation

due to cyclic (See Section

loading and SCC . . 3.3.2.1)

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Component Group, - Aging E ectl - ; AM A In GALL ; I - A A St v t-- cam . - mt~ I 0-;:ep,.7-

Components Loss of material Selective leaching Service Water Consistent with

(aluminum bronze, due to selective of materials Integrity (B.1 .24), GALL, which

crass, cast iron, leaching Perodic and recommends no

cast steel) in open- Preventive further evaluation

cycle and closed- Surveillance (See Section

cycle cooling water (B.1.18), Water 3.3.2.1)

systems, and Chemistry Control

ultimate heat sink (B.1 .30) (Item Number

3.3.1-29)

Fire barriers, walls, Concrete cracking Fire protection and Fire Protection Consistent with

ceilings, and floors and spalling due to structures (B.1.10) GALL, which

in fire protection freeze-thaw, monitoringrecommends no

(Item Number aggressive further evaluation

3.3.1-30) chemical attack, (See Section

and reaction with 3.3.2.1)

aggregates; loss of

material due to

corrosion

embedded steel l

The staff's review of the ANO-2 auxiliary system and associated components followed one of

several approaches. One approach, documented in Section 3.3.2.1 of this SER, involves the

staff's audit and review of the AMR results for components in the auxiliary system that the

applicant indicated are consistent with the GALL Report and do not require further evaluation.

Another approach, documented in Section 3.3.2.2 of this SER, involves the staff's audit and

review of the AMR results for components in the auxiliary system that the applicant indicated

are consistent with the GALL Report and for which further evaluation is recommended. A third

approach, documented in Section 3.2.2.3 of this SER, involves the staff's technical review of

the AMR results for components in the auxiliary system that the applicant indicated are not

consistent with the GALL Report, or are not addressed in the GALL Report. Section 3.0.3 of

this SER documents the staff's review of the AMPs that are credited to manage or monitor

aging effects of the auxiliary system components.

3.3.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application

In Sections 3.3.2.1.1 through 3.3.2.1.11 of the LRA, the applicant identified the materials,

environments, and aging effects requiring management. The applicant identified the following

programs that manage the aging effects related to the auxiliary system components:

0

0

0

0

0

0

Boric Acid Corrosion Prevention Program

System Walkdown Program

Water Chemistry Control Program

Bolting and Torquing Activities Program

Buried Piping Inspection Program

Fire Protection Program

Oil Analysis Program

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* Wall Thinning Monitoring Program

* Heat Exchanger Monitoring Program

* Periodic Surveillance and Preventive Maintenance Program

* Diesel Fuel Monitoring Program

* Service Water Integrity Program

* ~Flow-Accelerated Corrosion Program

Staff Evaluation'

In Tables 3.3.2-1 through 3.3.2-11 of the LRA, the applicant summarized the AMRs for the

auxiliary systems and identified which AMRs it considered to be consistent with the GALL

Report.

The staff conducted an audit of the information provided in the LRA and program bases,-

documents, which are available at the applicant's engineering office. On the basis of its audit,,.

the staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are consistent with the AMRs in the GALL Report. Therefore, the staff finds that the

applicant identified the applicable aging effects and they are appropriate for the combination of.

materials and environments listed.

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 does not recommend further

evaluation, the' staff performed an audit and review to determine whether the GALL Report

evaluation bounded the plant-specific components contained in these GALL Report component

groups.

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 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 determine 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 determine consistency

with the GALL Report. The staff determined that it had reviewed and accepted the identified

exceptions to the GALL AMPs. '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 is valid

for the site-specific conditions.

Note C indicates that the component for the'AMR line item is different but 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 could not

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

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a

items to determine consistency with the GALL Report. The staff also determined whether the

AMR line item of the different component applies to the component under review and whether

the AMR is valid for the site-specific conditions.

Note D indicates that the component for the AMR line item is different but 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

determine consistency with the GALL Report. The staff determined that the AMR line item of

the different component applies to the component under review. The staff determined that it

had reviewed and accepted the identified exceptions to the GALL AMPs. 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 is 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 determine consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review to confirm the applicant's claim that certain identified

AMRs are consistent with the staff-approved AMRs in the GALL Report. The staff reviewed the

information provided in the LRA and program bases documents, which were available at the

applicant's engineering office. The staff did not repeat its review of the matters described in the

GALL Report. However, the staff did determine that the material presented in the LRA was

applicable and that the applicant had identified the appropriate GALL AMRs. The staff

evaluation is discussed below.

3.3.2.1.1 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

The staff reviewed Table 3.3.1, Item Number 3.3.1-15, and associated AMRs consistent with

the GALL Report.

The applicant stated that it uses the plant-specific periodic surveillance and preventive

maintenance (PSPM) program (AMP B.1.18) to manage loss of material for heat exchanger

(bonnet and shell) components'exposed to treated water of the emergency diesel generator

system. The staff's evaluation of the PSPM program is documented in Section 3.0.3.3.7 of this

SER. The staff found that the use of the PSPM program in lieu of the auxiliary systems water

chemistry control program (AMP B.1.30.1) is not adequate for the carbon steel components of

the emergency diesel generator and alternate AC diesel generator systems that are exposed

internally to treated water. The PSPM program's emergency diesel generator maintenance

inspections detect aging effects but do not sample or control water chemistry to manage aging

effects. The auxiliary systems water chemistry control program, evaluated in Section 3.0.3.3.11

of this SER, controls and monitors water chemistry in addition to performing sampling and

analyses on the emergency diesel generator cooling water system.

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I
-

By letter dated March 24, 2004, the applicant stated that the auxiliary systems water chemistry

control program applies to the emergency diesel generator heat exchanger bonnet and shell in

treated water (page 3.3-51 of the LRA) rather than the PSPM program. Subsequently, by letter

dated May 19, 2004, the applicant committed, in response to Question B.1.30.1 -6, to update the

UFSAR supplement LRA Section A.2.1.31 to reflect industry guidance used for auxiliary

systems water chemistry control program (AMP B.1.30.1). This is now consistent with the.

GALL Report, and on that basis the staff finds it acceptable.

3.3.2.1.2 Loss of Material Due to General;,Pitting, Crevice, and Microbiologically Influenced.

Corrosion and Biofouling; Buildup of Deposit Due to Biofouling

The staff reviewed Table 3.3.1, Item Number 3.3.1-17, the AMP descriptions in the LRA, and

the associated AMRs consistent with the GALL Report.

The applicant stated that it uses the plant-specific, periodic surveillance and preventive

maintenance program (AMP B.1.18) to manage this aging effect. The staff's evaluation of the

PSPM program is documented in Section 3.0.3.3.7 of this SER. The staff found that the use of

the PSPM program in lieu of the service water integrity program (AMP B.1.24) is not acceptable

for managing the loss of material aging effect for emergency diesel generator heat exchanger

bonnets in a fresh, raw water environment.

By letter dated March 24, 2004, the applicant stated that the PSPM program manages loss of

material for the emergency diesel generator heat exchanger bonnet in fresh raw water

(page 3.3-51 of the LRA) in Table 3.3.2-3 through periodic internal inspections during

emergency diesel generator overhauls. The applicant further stated that, in addition to the

periodic surveillance and preventive maintenance ,program, the service water integrity program

is conservatively included as an AMP since it provides additional aging management of this

component. The evaluation of this program is discussed in Section 3.0.3.2.7 of this SER. On

the basis of the review of the service water integrity program and the applicant's response, the

staff finds this acceptable. ,, . . . :;

On the basis of its audit and review, the staff determined that for all other AMRs not requiring

further evaluation, as identified in the Table 3.3.1 (Table 1), the applicant's references to the

GALL Report are acceptable and no further staff review is required.

Conclusion

The staff has evaluated the applicant's claim of consistency with GALL Report. The staff also

has reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review,

the staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are consistent with the AMRs in the GALL Report. Therefore, the staff finds that the

applicant has demonstrated that the effects of aging for these components can be adequately

managed so that their intended function(s) can be maintained consistent with the CLB for the

period of extended operation, as required by-.10 CFR 54.21 (a)(3).

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging can be adequately managed so that the intended function(s) can be

maintained consistent with the CLB for the period of extended operation, as required by

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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 Section 3.3.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for auxiliary systems. The applicant provided information

concerning how it will manage the following aging effects:

* loss of material due to general, pitting, and crevice corrosion

* hardening and cracking or loss of strength due to elastomer degradation or loss of

material due to wear

* cumulative fatigue damage

* crack initiation and growth due to cracking or stress-corrosion cracking

* loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion

* loss of material due to general, galvanic, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and biofouling

* quality assurance for aging management of nonsafety-related components

* crack initiation and growth due to stress-corrosion cracking and cyclic loading

* reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion

Staff Evaluation

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 reviewed the applicant's evaluation to determine whether it adequately

addressed the issues in need of further evaluation. In addition, the staff audited the applicant's

additional evaluations against the criteria contained in Section 3.3.2.2 of the Standard Review

Plan for License Renewal. The audit report issued August 19, 2004, documents the details of

the staff's audit.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

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3.3.2.2.1 Loss of Material due to General, Pitting, and Crevice Corrosion

In Section 3.3.2.2.1 of the LRA, the applicant addressed loss of material in components of the

spent fuel pool system.

Section 3.3.2.2.1 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion could occur in the channel head and access cover, tubes, and tubesheets of the heat

exchanger in the spent fuel pool cooling and cleanup. The Water Chemistry Program relies on

monitoring and control of reactor water chemistry based on the EPRI guidelines of TR-1 05714

for primary water chemistry and TR-1 02134 for secondary water chemistry to manage the

effects of loss of material due to general, pitting, or crevice corrosion. However, high;

concentrations of impurities at crevices and locations of stagnant flow conditions could cause

general, pitting, or crevice corrosion. Therefore, the applicant should assess the effectiveness

of the Chemistry Control Program 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 assess the effectiveness of the Water Chemistry Program. A one-time

inspection of selected components at susceptible locations is an acceptable method for -

ensuring that corrosion is not occurring and that the components' intended function will be

maintained during the period of extended operation. No loss of material aging effects are

observed for stainless steel components exposed to air.

Further, Section 3.3.2.2.1 of the SRP-LR states that loss of material due to pitting and crevice

corrosion could occur in the filter housing, valve bodies, and nozzles of the ion exchanger in the

spent fuel pool cooling and cleanup system.!The Water ChemistryProgram relies on

monitoring and control of reactor water chemistry based on the EPRI guidelines of TR-1 05714

for primary water chemistry and TR-1 02134 for secondary water chemistry to manage the

effects of loss of material due to pitting or crevice corrosion. However, high concentrations of

impurities at crevices and locations of stagnant flow conditions could cause pitting or crevice

corrosion. Therefore, the applicant should evaluate the effectiveness of the Chemistry Control

Program to'ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage loss of material due to pitting and crevice corrosion to*

evaluate the effectiveness of the WaterChemistry 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. -:a -

The applicant stated that the portion of the spent fuel pool system that supplies emergency

makeup is subject to an AMR, and the applicant credited the Primary and Secondary Water

Chemistry Control Program (AMP B.1.30.3) with managing loss of material. The staff reviewed

the Primary and Secondary Water Chemistry Control Program and documented its evaluation in

Section 3.0.3.1 of this SER. The Water Chemistry Control Program, in conjunction with

anticipated future maintenance activities, provides for the inspection of systems when they are

opened for maintenance, which addresses the verification program recommendation in the

GALL Report. The Water Chemistry Control Program is credited with managing loss of

material for stainless steel components in this portion of the spent fuel pool system that are

exposed to borated treated water. This is consistent with the GALL Report and acceptable to

the staff. , ,

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3.3.2.2.2 Hardening and Cracking or Loss of Strength due to Elastomer Degradation or Loss of

Material due to Wear

In Section 3.3.2.2.2 of the LRA, the applicant addressed the potential for degradation of

elastomers in collars and seals in spent fuel cooling systems and ventilation systems.

Section 3.3.2.2.2 of the SRP-LR states that hardening and cracking due to elastomer

degradation could occur in elastomer linings of the filter, valve, and ion exchangers in spent fuel

pool cooling and cleanup systems. Hardening and loss of strength due to elastomer

degradation could occur in the collars and seals of the duct and in the elastomer seals of the

filters in the control room area, auxiliary and radwaste area, and primary containment heating

ventilation systems and in the collars and seals of the duct in the diesel generator building

ventilation system. Loss of material due to wear could occur in the collars and seals of the duct

in the ventilation systems. The GALL Report recommends further evaluation to ensure

adequate management of these aging effects.

The applicant stated that the portion of the spent fuel pool system that is subject to an AMR

contains no elastomers. The applicant stated that for the ventilation systems, it uses the

plant-specific Periodic Surveillance and Preventive Maintenance Program (AMP B.1.18) to

manage degradation of elastomers. The staff reviewed this program and concludes that it is

acceptable. Section 3.0.3.3.7 of this SER documents this evaluation.

The applicant further stated that for other systems, the PSPM Program, supplemented by the

Fire Protection Program (AMP B1.10), manages elastomer degradation. The staff reviewed the

Fire Protection Program, as documented in Section 3.0.3.2.5 of this SER.

The staff finds that the PSPM Program is an acceptable program for managing cracking and

change in material properties for elastomer expansion joints and flex hose in the alternate ac

diesel generator system and the fuel oil system exposed to outdoor air and air expansion joints

associated with control room and auxiliary building heating, ventilation, and air conditioning

(HVAC) systems. However, Section 3.3.2.2.2 of the LRA states, "Elastomers are used in other

[other than spent fuel pool and ventilation systems] systems. For these systems, management

of elastomer degradation is provided by the PSPM program supplemented by the fire protection

program." Based on this statement, the staff finds that the PSPM Program should be

supplemented by the Fire Protection Program for elastomers in the alternate ac diesel

generator and water suppression fire protection systems.

By letter dated March 24, 2004, the applicant stated that for these systems, the PSPM

Program, supplemented by the Fire Protection Program, manages elastomer degradation. The

words "supplemented by" mean that for fire protection elastomers, the Fire Protection Program

is used instead of the PSPM Program. The staff finds assignment of these AMRs to the Fire

Protection Program to be acceptable.

3.3.2.2.3 Cumulative Fatigue Damage

As stated in the SRP-LR, fatigue is a TLAA as defined in 10 CFR 54.3. The TLAAs must be

evaluated in accordance with 10 CFR 54.21 (c)(1). Section 4.3 of this SER documents the

staff's review of the applicant's evaluation of this TLAA. In performing this review, the staff

followed the guidance in Section 4.3 of the SRP-LR.

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3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress-Corrosion Cracking

In Section 3.3.2.2.4 of the LRA, the applicant addressed the potential for cracking in the highpressure pumps of the CVCS.

Section 3.3.2.2.4 of the SRP-LR addresses crack initiation and growth due to cracking in the

high-pressure pump in the CVCS. The GALL Report recommends further evaluation to ensure

that these aging effects are adequately managed.

In the ESF section of the GALL Report, Volume 2, Item V.D.1.1 -a, the management of stainless

steel components performing a pressure boundary function is addressed by using the Water

Chemistry Program. The applicant stated that it uses the Primary and Secondary Water.

Chemistry Control Program (AMP B.1.30.3) to manage cracking and SCC of these stainless

steel components. Section 3.0.3.1 of this SER documents the staff's review of the Primary and

Secondary Water Chemistry Control Program. The program is consistent with the GALL Report

and therefore acceptable to the staff.

3.3.2.2.5 Loss of Material due to General; Microbiologically Influenced, Pitting, and Crevice

Corrosion -

In Section 3.3.2.2.5 of the LRA, the applicant addressed the loss of material due to corrosion

that could occur on internal and external surfaces of components exposed to air and the

associated range of atmospheric conditions.,

Section 3.3.2.2.5 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion could occur in the piping and filter housing and supports in the control room area, in

the auxiliary and radwaste area, in the primary containment heating and ventilation systems, in

the piping of the diesel generator building ventilation system, in the aboveground piping and

fittings,'valves, and pumps in the diesel fuel oil system, and in the diesel engine starting air,

combustion air intake, and combustion air exhaust subsystems in the emergency diesel.

generator system. Loss of material due to general, pitting, crevice, and MIC could occur in the

duct fittings, access doors, and closure bolts, equipment frames and housing of the duct. Loss

of material due to pitting and crevice corrosion could occur in the heating/cooling coils of the air

handler heating/cooling, and loss of material due to general corrosion could occur on the

external surfaces of all carbon steel SCs, including bolting exposed to operating temperatures

less than 212 0F in the ventilation systems:, The GALL Report recommends further evaluation

to ensure adequate management of these aging effects.

The applicant credited the System Walkdown Program (AMP B.1.28) for managing loss of

material of carbon steel components in the spent fuel pool, emergency diesel generator,

alternate ac diesel generator, fuel oil, water suppression fire protection, service water, and the

control room and auxiliary building HVAC systems for external and internal surfaces exposed to

air and outdoor air. The staff reviewed the System Walkdown Program'and concludes that it is

acceptable. Section 3.0.3.3.9 of this SER documents its evaluation.

The applicant stated that it uses the plant-specific PSPM Program (AMP B.1.18) to manage

loss of material for the external surfaces of emergency diesel generator and alternate Ac diesel

generator system carbon steel components with internal 'exposure to'exhaust gas, treated and

untreated air, outdoor air, and the control room and auxiliary building HVAC systems. The

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PSPM Program is also used for managing loss of material of carbon steel components in an

external environment of air in the Halon fire protection and reactor coolant pump motor oil

leakage collection system. The staff reviewed the PSPM Program and concludes that it is

acceptable. Section 3.0.3.3.7 of this SER documents the staff's evaluation.

The applicant credited the Wall Thinning Monitoring Program (AMP B.1.29) for managing loss

of material from the internal surfaces of the emergency diesel generator and alternate AC

diesel generator system carbon steel piping, silencer, and tank with internal exposure to

exhaust gas and untreated air. The staff reviewed the Wall Thinning Monitoring Program and

concludes that it is acceptable. Section 3.0.3.3.1 0 of this SER documents this evaluation.

3.3.2.2.6 Loss of Material due to General, Galvanic, Pitting, and Crevice Corrosion

In Section 3.3.2.2.6 of the LRA, the applicant addressed further evaluation of programs to

manage loss of material in the reactor coolant pump oil collection system to evaluate the

effectiveness of the Fire Protection Program.

Section 3.3.2.2.6 of the SRP-LR states that loss of material due to general, galvanic, pitting,

and crevice corrosion could occur in tanks, piping, valve bodies, and tubing in the RCP oil

collection system in fire protection. The Fire Protection Program relies on a combination of

visual and volumetric examinations in accordance with the guidelines of 10 CFR Part 50

Appendix R and Branch Technical Position 9.5-1 to manage loss of material due to corrosion.

However, corrosion may occur at locations where water from washdowns may accumulate.

Therefore, the applicant should assess the effectiveness of the program to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of programs to

manage loss of material due to general, galvanic, pitting, and crevice corrosion to determine

that the effectiveness of the program. A one-time inspection of the bottom half of the interior

surface of the tank of the RCP oil collection system 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 applicant stated that it uses the plant-specific Periodic Surveillance and Preventive

Maintenance Program (AMP B.1.18) to manage loss of material in lieu of the one-time

inspection. Carbon steel components in this system are included in the visual inspection for

loss of material and will be monitored for degradation. The staff reviewed the PSPM Program

and finds that the program will adequately manage the effects of aging so that the intended

functions will be maintained. Section 3.0.3.3.7 of this SER documents its evaluation.

3.3.2.2.7 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion and Biofouling

In Section 3.3.2.2.7 of the LRA, the applicant addressed further evaluation of programs to

manage loss of material in the diesel fuel oil system to determine the effectiveness of the diesel

fuel monitoring program.

Section 3.3.2.2.7 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion, MIC, and biofouling could occur in the internal surface of tanks in the diesel fuel oil

system and due to general, pitting, and crevice corrosion and MIC in the tanks of the diesel fuel

oil system in the EDG system. The existing AMP relies on the fuel oil chemistry program for

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monitoring and control of fuel oil contamination in accordance with the guidelines of ASTM

Standards D4057, D1796, D2709 and D2276 to manage loss of material due to corrosion or

biofouling. Corrosion or biofouling may occur at locations where contaminants accumulate.

Verification of the effectiveness of the chemistry control program should be performed to

ensure that corrosion is not occurring.- The GALL Report recommends further evaluation of

programs to manage corrosion/biofouling to determine the effectiveness of the 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 applicant stated that it uses the diesel fuel monitoring program (AMP B.1.7) to manage loss

of material for the diesel fuel oil system. This program also provides for the periodic inspection.

of the fuel oil tanks, which addresses the one-time inspection recommendation in the GALL

Report.

The staff reviewed the diesel fuel monitoring program and finds that the program will

adequately manage the effects of aging so that the intended functions will be maintained. Its

evaluation is documented in Section 3.0.3.1 of this SER.

3.3.2.2.8 Quality Assurance for Aging Management of Nonsafety-Related Components

Section 3.0.4 of this SER provides a separate evaluation of the applicant's Quality Assurance

Program.

3.3.2.2.9 Crack Initiation and Growth due to Stress-Corrosion Cracking and Cyclic Loading

In Section 3.3.2.2.9 of the LRA, the applicant addressed further evaluation of programs to

manage cracking in the CVCS to determine the effectiveness of the Water Chemistry Control

Program.,

Section 3.3.2.2.9 of the SRP-LR states that crack initiation and growth due to SCC and cyclic

loading could occur in the channel head and access cover, tubesheet, tubes, shell and access,

cover, and closure bolting of the regenerative heat exchanger and in the channel head and

access cover, tubesheet, and tubes of the letdown heat exchanger in the CVCS. The Water

Chemistry Program relies on monitoring and control of water chemistry based on the guidelines

of TR-105714 for primary water chemistry to manage the effects of crack initiation and growth

due to SCC and cyclic loading. The applicant should determine the effectiveness of the

Chemistry Control Program to ensure that crack initiation and growth are not occurring. The

GALL Report recommends further evaluation to manage crack initiation and growth due to SCC

and cyclic loading for these systems to determine, the effectiveness of the Water, Chemistry

Program. A one-time inspection of selected components and susceptible locations is an

acceptable method to ensure that crack initiation and growth are not occurring and that the

component's intended function will be maintained during the period of extended operation. -.

The GALL Report recommends that the Water Chemistry Program be augmented by

determining the absence of cracking due to SCC and cyclic loading, or loss of material due to

pitting and crevice corrosion. 3⁄4The GALLtReport states that an acceptable verification program -

should include temperature and radioactivity monitoring of the shell-side water and eddycurrent testing of tubes. ' .

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The applicant credited the Primary and Secondary Water Chemistry Control Program

(AMP B.1.30.3) with minimizing cracking in the heat exchangers and providing for the

inspection of systems when they are opened for maintenance. This inspection of opened

systems is used to address the verification program recommendation in the GALL Report. The

staff reviewed the Primary and Secondary Water Chemistry Control Program and concludes

that it is acceptable. Section 3.0.3.1 of this SER documents its evaluation.

Because the GALL Report recommends the Water Chemistry Control Program for managing

SCC and cyclic loading, supplemented by a plant-specific program, the staff finds the use of the

Primary and Secondary Water Chemistry Control Program acceptable. The inspection of these

heat exchangers whenever they are opened for maintenance is an acceptable substitute for the

one-time inspection of susceptible locations.

3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of Material due to General

Corrosion

In Section 3.3.2.2.10 of the LRA, the applicant addressed reduction of neutron-absorbing

capacity and loss of material due to general corrosion, which could occur in the neutronabsorbing sheets of the spent fuel storage rack in the spent fuel storage.

Section 3.3.2.2.10 of the SRP-LR states that reduction of neutron-absorbing capacity and loss

of material due to general corrosion could occur in the neutron-absorbing sheets of the spent

fuel storage rack in the spent fuel storage. The GALL Report recommends further evaluation to

ensure that these aging effects are adequately managed.

The applicant stated that it does not credit the sheets of neutron-absorbing materials affixed to

the spent fuel racks with neutron absorption and stated that ANO-2 components are not subject

to this aging effect. Because the sheets of the neutron-absorption materials affixed to the spent

fuel racks are not credited with neutron absorption, the staff finds that this aging effect is not

applicable to ANO-2.

3.3.2.2.11 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

In Section 3.3.2.2.11 of the LRA, the applicant addressed the potential for loss of material in

buried piping of the service water and diesel fuel oil systems.

Section 3.3.2.2.11 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion and MIC could occur in the underground piping and fittings in the open-cycle cooling

water system (SW system) and in the diesel fuel oil system. 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 due to general, pitting, and crevice

corrosion and MIC. The effectiveness of the Buried Piping and Tanks Inspection Program

should be reviewed to evaluate an applicant's inspection frequency and operating experience

with buried components, thus ensuring that loss of material is not occurring.

The applicant credited the Buried Piping Inspection Program (AMP B.1.4) with managing loss of

material for buried components of the service water and diesel fuel oil systems. This is

consistent with GALL AMP XI.M34, "Buried Piping Inspection.' The staff reviewed the

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applicant's operating history and found that the frequency of pipe excavation was sufficient to

manage the effects of loss of material. The staff reviewed the Buried Piping Inspection

Program and concludes that it is acceptable. Section 3.0.3.2.2 of this SER documents its

evaluation.

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 that it further evaluated. In addition, the staff reviewed the applicant's

additional evaluations against the criteria contained in Section 3.3.2.2 of the SRP-LR. The staff

finds that the applicant has demonstrated that it can adequately manage the effects of aging so

that the intended functions can be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3 AMR Results That Are Not Consistent with the GALL Report

Summary of Technical Information in the AbDlication

In Tables 3.3.2-1 through 3.3.2-11 of the LRA, the applicant gave additional details of the

results of the AMRs for material, environment, aging effects requiring management, and AMP

combinations that are not consistent with the GALL Report.

In Tables 3.3.2-1 through 3.3.2-11, the applicant indicated, via Notes F through J,-that neither

the identified component nor the material and environment combination is evaluated in the

GALL Report and provided information concerning how it will manage the aging effects

requiring management.: -

Note F indicates that the material is not in the GALL Report for the identified compone.nt.

Note G indicates that the environment is not in the GALL Report for the identified componennt

and material. ' . - -

Note H indicates that the aging effect is not in the GALL Report for the component, material,

and environment combination.

Note I indicates that the aging effect in the GALL Report for the identified component, material,

and environment combination is not applicable.,..

Note J indicates that neither the identified component nor the material and environment

combination is evaluated in the GALL Report. n ,;, , ,

For component type, material, and environment combination that are not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

function will be maintained consistent with the CLB during the period of extended operation.

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Staff Evaluation

3.3.2.3.0 General RAls on AMR Issues

By letter dated May 5, 2004, the staff requested the applicant to provide additional information

on the issues described in the following general RAls. By letters 2CAN060402 and

2CAN060404 dated June 21, 2004, the applicant responded to these RAls. These RAls, the

applicant's responses and the staff's evaluation of the responses are described below.

Cracking Fatigue (RAI 3.3-1)

LRA Tables 3.3.2-5 and 3.3.2-11 identify cracking-fatigue as an aging effect requiring aging

management, but LRA Section 4.3.2 states that, "Engineering evaluations identified no nonclass 1 pressure vessels, heat exchangers, storage tanks or pumps requiring evaluation for

thermal fatigue." The applicant credits the periodic surveillance and preventive maintenance

program for managing this aging effect in the CVCS pump casing and the system walkdown

aging management program for various components in miscellaneous systems in scope for

1 OCFR54.4(a)(2). The applicant was requested to clarify the type of fatigue managed by these

inspections, the basis for these inspections in lieu of a TLAA and explain how the inspections

are effective in detecting internal cracks prior to loss of the intended function, including

operating experience.

By letter dated June 21, 2004, the applicant responded by providing the following information:

Type of Fatigue (Part 1)

The applicant stated that, for the CVCS pump casing (charging pumps), as identified in LRA

Table 3.3.2-5, cracking due to high-cycle fatigue (as a result of deflection of the plunger cap

during a pump cycle) is the aging effect identified. For the components in miscellaneous

systems in scope for 1 OCFR54.4(a)(2), as identified in LRA Table 3.3.2-11, the aging effect

managed is cracking due to thermal fatigue.

Basis for Inspections in Lieu of a TLAA (Part 2)

In reference to Table 3.3.2-5, the applicant stated that cracking of the charging pump plunger

cap (pump casing) was discovered during plant operation and documented in the Corrective

Action Program. Neither an analysis involving time-limited assumptions defined by the current

operating term nor a requirement for such an analysis was found for this condition during the

identification of TLAAs for license renewal. Components in LRA Table 3.3.2-11 are generally

nonsafety-related components designed in accordance with American Society of Mechanical

Engineers B.31.1 with an implicit analysis limit of 7000 thermal cycles. Cracking due to thermal

fatigue was conservatively identified as an aging effect requiring management although it is not

expected to occur. If cracking due to thermal fatigue were to occur, the System Walkdown

Program would manage this aging effect as described in part 3 of this response.

Effectiveness of Inspections (Part 3)

The applicant stated that, for the charging pump plunger cap, a preventive maintenance task

exists to disassemble and inspect the charging pumps and plungers. Operating experience has

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shown this inspection to be effective in identifying'the effects of aging prior to loss of system

function. For components in LRA Table 3.3.2-11, system walkdowns detect leakage and spray

from liquid-filled systems. Industry operating experience has shown that age-related failures of

nonsafety-related structures, systems, and components, (SSCs) containing steam or liquid that'

could prevent safety-related components from-accomplishing their safety function have only

occurred as a result of loss of material 'due to flow-accelerated corrosion (FAC), which is

managed by the FAC Program. Leakage from causes other than FAC has been limited in

extent such that it has been identified and corrected through normal operational activities or

system walkdowns prior to loss of system functions.?For further information on how the System

Walkdown Program is effective in managing this aging effect see response to RAI 3.3.2.4.11-1.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response'to RAI 3.3-1 and determined that the applicant's

response does not completely resolve the staff's concerns. However, in general, the staff found

the applicant's response adequate and acceptable because the applicant has identified the type

of fatigue, the basis for inspections rather than a TLAA and information to support the

effectiveness of the inspections.

The staff found that the high-cycle fatigue identified by the applicant as applicable to the

charging pumps due to deflection of the plunger cap during a pump cycle to be appropriate for

a reciprocating type pump. The staff also found that thermal fatigue identified by the applicant

for miscellaneous systems in scope'of 1 OCFR54.4(a)(2) to be appropriate on the basis that

thermal fatigue is'addressed in the ASME codes for systems that experience thermal cycles.

In regard to the basis for inspections rather than 'a TLAA for these components,- the staff found

the applicant response adequate-and acceptable in that a requirement does not exist in the

ASME codes of record for the charging pump casing or ASME B31.1 piping. 'Therefore,

periodic inspections are considered to be appropriate in lieu of a TLAA to manage fatiguecracking in these'components.'

The staff found that the information submitted to support the effectiveness of the charging,

pump inspections to be adequate and acceptable. -The staff considers the identified

maintenance tasks to disassemble and inspect the charging pumps and plungers to be

appropriate for managing fatigue-cracking. However, the operating experience submitted by

the applicant response to support the-effectiveness 'of the Walkdown Program to manage

fatigue-cracking in miscellaneous systems in scope for 1 OCFR54.4(a)(2) by visual inspections

for leakage is not sufficient and requires additional basis for acceptability. This concern is

addressed under RAI 3.3.2A.1 1-1 -

The staff was also concerned that the Periodic Surveillance and Preventive Maintenance

Program (PSPM) and AMR Table 3.3.2-5 do not address fatigue cracking in the charging pump

bolting and the PSPM does not address fatigue-cracking'in the casing. The staff identified this

as potential open item and requested the applicant to clarify how the PSPM or other aging

management program manages fatigue cracking' in the charging pump casing and bolting.

By letter dated September 10, 2004, the applicant identified that, although cracking due to

fatigue of the chdrging pump block was not identified as a likely failure mechanism, the pump

block will be periodically inspected for indication's of cracking. The applicant clarified that during

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maintenance inspections, plunger caps and blocks are visually inspected for indications of

cracking and indications of cracking results in additional non-destructive examination (such as

dye penetrant tests) and replacement of the affected component if cracking is confirmed. In this

letter the applicant also explained that cracking of bolting due to high cycle fatigue is not a

concern for license renewal since it would be discovered during the current license period in

most cases where systems are frequently operated. The applicant response also stated that

there have been no instances of pump casing bolting requiring replacement due to cracking or

other defects. The applicant further identified that during regular pump maintenance (each

pump has historically been repacked two to three times a year), bolting is inspected for defects.

The applicant clarified that evidence of cracking would be detected during these inspections.

The applicant's response is adequate and acceptable to resolve the staff's concern because the

applicant has clarified that maintenance inspections of the charging pump will detect fatiguecracking in the pump block and, although most cases of high cycle fatigue would be detected

during the current license period, evidence of fatigue-cracking in bolting would be detected by

bolting inspections during regular pump maintenance. All issues related to RAI 3.3-1 are

resolved.

Chemistry Control Programs and Verification Inspections (RAI 3.3-2)

The LRA aging management evaluation credits the water chemistry control program for

managing aging effects for various components in the auxiliary systems, but it is not clear which

specific subprogram is used to manage each component. The applicant was requested to

clarify which subprogram manages each auxiliary system component. The applicant was also

requested to identify any additional inspection programs such as one-time inspections, to

determine the effectiveness of the chemistry control program. The applicant was further

requested to provide a description of the elements of the inspection program as defined in

Appendix A.1 of the SRP-LR including details such as inspection methods, how susceptible

locations are determined, basis for inspection population and sample size, timing, acceptance

criteria including codes and standards, and operating experience. LRA Table B-1 identifies

that one-time inspections are not applicable. If periodic inspections are planned rather than

one-time inspections, the applicant was requested to identify the frequency. If opportunistic

inspections are planned rather than one-time inspections, the applicant was requested to

explain how the program assures that the inspections will be completed prior to end of the

existing operating license. The applicant was also requested to identify any specific operating

experience (i.e.; inspection results) relevant to inspections to determine effective chemistry

control in auxiliary systems that demonstrate the effectiveness of the inspection program.

By letter dated June 21, 2004, the applicant responded by providing the following information:

Water Chemistry Control Programs to Manage Aging Effects for Various Components in the

Auxiliary Systems (Part a)

Components in Table 3.3.2-1, Spent Fuel Pool System, and Table 3.3.2-5, Chemical and

Volume Control System, that list water chemistry control as the program are included in the

Primary and Secondary Water Chemistry Control Program.

Components in Table 3.3.2-3, Emergency Diesel Generator (EDG) System, and Table 3.3.2-4,

Alternate AC (MC) Diesel Generator System, that list water chemistry control as the program

are included in the Auxiliary Systems Cooling Water Chemistry Control Program.

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Components in Table 3.3.2-11, Miscellaneous Systems in Scope for 1 OCFR54.4(a)(2), that list

water chemistry control as the program are included in the program that applies to the system:

in which the component resides. Since all of the water chemistry control subprograms provide

assurance that the aging effect loss of material 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, the particular subprogram for a specific

component is beyond the level of detail necessary in the table.

Effectiveness of the Water Chemistry Programs (Part b)

The applicant stated that the effectiveness of the.water chemistry programs at ANO-2 has been

confirmed through routine component inspections that are performed by chemistry,.

maintenance and engineering personnel. This includes the Primary and Secondary, Closed

Cooling, and Auxiliary Systems Water Chemistry Programs. These inspections were performed

when primary and secondary systems were opened for maintenance, when an adverse

chemistry trend existed, or when requested by the chemistry or engineering departments. The

areas inspected have included areas that are susceptible to the aging effects identified in the

license renewal application. In addition; for many reactor coolant system components included

in the Primary and Secondary Water Chemistry Control Program, inspection activities within

other aging management programs provide additional confirmation of chemistry program

effectiveness. These other programs include.the Inservice Inspection, Alloy 600 Aging

Management; Cast Austenitic Stainless Steel Evaluation, Pressurizer Examinations, Reactor

Vessel Internals Inspection, and Steam Generator Integrity Programs. Some components,-

such as heat exchangers, have been inspected periodically providing repetitive evidence that

the water chemistry programs are adequately managing aging effects. If, during these

inspections significant abnormal conditions were noted, including those that were the result of

aging effects such as loss of material and cracking, these conditions would have been

documented under the Corrective Action Program. Actions to determine the cause of the -

condition and corrective actions to prevent recurrence would have then been taken. The

Generic Aging Lessons Learned (GALL) One Time Inspection Program XL.M32 focuses on the

most susceptible material and environment combinations in the most susceptible locations.

Items such as heat exchangers, piping and valves normally in standby, and system low points

or stagnant areas are representative of these susceptible locations. At ANO-2, inspections

have been performed in systems such as emergency feedwater, (EFW) and EDGs which are

normally in standby, steam generators, condensate storage tanks, feedwater heaters, moisture

separator reheaters, chillers, main steam safety valves, and blowdown heat exchangers. All of

these components are made of susceptible materials (stainless and carbon steel) and are -

exposed to environments (treated water and steam) that would be conducive to aging effects:

managed by the water chemistry programs.

Many components in the steam generators are inspected under other aging management

programs that provide additional assurance that significant degradation is not occurring and

that the-Primary.and Secondary Water Chemistry Control Program is effective. These

inspection activities include those contained in the Inservice Inspection and Steam Generator

-Integrity Programs. The inspection results of steam generator components are also applicable

to the main steam,-main feedwater and EFW, components with the same material and

environment combinations. -

As additional confirmation of the effectiveness of water chemistry programs, the ANO-2 review

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A

of operating experience included a review of condition reports (CRs), CR trending data, and

interviews with site personnel regarding water chemistry program operating experience. The

operating experience review did not identify component failures or significant adverse

conditions that were the result of an ineffective water chemistry program. Also, the CR trending

data did not identify recurrent component degradation occurring in the systems covered under

this aging management program. The review of CRs, CR trending data, and personnel

interviews provided additional confirmation of chemistry program effectiveness.

The combination of inspections under the Inservice Inspection Program, the Steam Generator

Integrity Program, and maintenance and routine chemistry inspections as a whole, constitute a

more thorough confirmation of water chemistry aging management program effectiveness than

could be. obtained from one-time inspections of a sample of items.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-2 and determined that the response

does not entirely resolve the issues concerning chemistry programs applied to components in

miscellaneous systems in part a) of the response and chemistry verification inspections

addressed in part b) of the response. The staff identified a potential open item and requested

the applicant to clarify whether auxiliary system inspections are limited to opportunistic

inspections and explain how the ANO-2 chemistry program verification inspections provide an

appropriate sample size required by the GALL one-time inspection program. The applicant was

also requested to clarify how the chemistry verification inspections will be completed prior to the

period of extended operation. Alternatively, the LRA may identify the application of planned

maintenance inspections for auxiliary systems such as the periodic surveillance and preventive

maintenance program or the use of future one-time inspections consistent with GALL.

By letter dated August 18, 2004, the applicant clarified that while many auxiliary system

inspections are opportunistic, some are performed periodically. The applicant identified specific

auxiliary system material and environmental groups crediting the water chemistry control

programs and stated that inspections have confirmed the effectiveness of water chemistry

control programs in managing the effects of aging on auxiliary system components.

The staff was concerned that the limited sample of auxiliary system components inspected may

not have been sufficient to conclude that the effectiveness of the water chemistry programs has

been confirmed and additional inspections may be required. The applicant was requested to

provide technical justification that an adequate sample size has been or will be selected prior to

the period of extended operation on the basis of industry criteria/operating experience.

By letter dated September 10, 2004 the applicant responded that the sample of components is

sufficient to conclude that the effectiveness of the water chemistry programs has been

confirmed and additional inspections are not required. The applicant stated that a review of

maintenance data for the past five years indicates that the number of inspections completed for

each group exceeds the minimum number of random samples necessary to obtain a 90%

confidence level that aging effects would have been identified, if present. The applicant further

stated, "Therefore, the sample of components inspected is sufficient to conclude that the

effectiveness of the water chemistry programs has been confirmed and additional inspections

are not required."

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The staff was concerned that, if no future one-time or periodic inspections are performed,

detection of potential aging effects in the future may not be adequately detected or corrected.

GALL AMP XL.M32 specifically identifies that the'inspection not be scheduled too early in the

current operating term, which could raise questions regarding continued absence of aging - effects prior to and near the extended period of operation. The applicant was requested to -

clarify that future chemistry, ISI and maintenance inspections combined with past inspections

constitute an adequate sample size to determine chemistry control or provide justification for

not performing future inspections close to the end of the current operating license.

By letter dated September 23, 2004, the applicant clarified that maintenance activities are not

expected to decline and it is proper to assume that maintenance history is representative of

future numbers and diverse locations of anticipated maintenance inspections. The applicant

concludes that past chemistry, maintenance and inservice inspections combined with future

anticipated inspections constitute an adequate sample size to determine that the water.

chemistry programs are managing aging effects so that intended functions will be maintained

during the period of extended operation.

The staff found the applicant's response to issues concerning chemistry control verifications for

auxiliary systems to be adequate and acceptable because the applicant has identified that a

combination of past chemistry, maintenance and inservice inspections combined with future

anticipated inspections constitute an adequate sample size to determine that the water

chemistry programs are managing aging effects so that intended functions will be maintained

during the period of extended operation. All issues pertaining to RAI 3.3-2 are resolved.

Inspection Criteria for Flex Hose (RAI 3.3-3);

LRA Tables 3.3.2-3 and 3.2.3-7 state that flex hose exposed to an internal treated water and

untreated air environments, and fuel oil environment, respectively, are managed by the periodic

surveillance and preventive maintenance program.' The description of the periodic surveillance

and preventive maintenance program in LRA Section B.1.1 8 does not identify inspection criteria

for the flex hose. The applicant was requested to identify the method of maintenance

inspections applied to the flex hose, the frequency of inspections and the technical basis for the

inspections. If inspection is limited to the external surfaces, the applicant was requested to:

justify the basis considering manufacturer's recommendations, industry practices and operating

experience. The applicant was also requested to clarify if elastomer hoses used in auxiliary

systems are to be replaced at specified intervals according to manufacturer's recommendations

and standard industry practice.

By letter dated June 21, 2004, the applicant responded by providing the following information:

The details on inspection criteria and frequency for the flex hoses that are included in

the Periodic Surveillance and Preventive Maintenance Program will be determined prior

to entering the period of extended operation. kIt is expected that a visual inspection of i;

the internal and external surfaces will be performed. However, it may be determined

that periodic replacement of the hoses is preferable and inspections will not be

performed. None of these hoses are replaced on a specified interval since no

replacement frequency was specified by the original manufacturer. If replaced at

specific intervals,-flex hoses would be considered short-lived and not subject to aging

management review.

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In their letter dated June 21, 2004 the applicant identified a specific commitment that the details

of the inspection criteria and frequency of the flex hoses that are included in the Periodic

Surveillance and Preventive Maintenance Program will be determined prior to the period of

extended operation. It is expected that a visual inspection of the internal and external surfaces

will be performed. However, it may be determined that periodic replacement of the hoses is

preferable and inspections will not be performed.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-3 and determined that the response

does not entirely resolve the issues concerning inspection criteria for flexible hoses. In a

meeting with the applicant on July 20, 2004, the staff requested the applicant to identify criteria

for inspection of flexible hoses managed by the periodic surveillance and preventive

maintenance program and to identify a commitment to have plant procedures updated prior to

the period of extended operation. By letter dated August 18, 2004 the applicant provided the

following response:

As stated in the response to RAI 3.3-3, the PSPM Program will manage the effects of

aging on flexible hoses through visual examination of external and internal surfaces.

The visual examination looks for evidence of cracking and changes in material

properties such as loss of flexibility and embrittlement. The flexibility of the hoses will be

verified through manual manipulation of the hose concurrent with visual inspection. If

evidence of degradation is detected, the hoses will be replaced. These hoses will be

inspected at least once every 10 years. The hoses that credit the PSPM program are in

the emergency diesel generator, fuel oil, alternate AC, and nitrogen systems.

Procedures and preventive maintenance tasks for the inspection of flex hoses in these

systems using the above criteria will be implemented prior to the period of extended

operation. Alternatively, periodic replacement of the hose may be implemented in lieu of

periodic inspection.

This response is adequate and acceptable because specific inspection criteria and a

commitment for implementation were identified to demonstrate that the flexible hoses will be

inspected both externally and internally at specified frequencies to provide assurance that the

aging effects will be detected and corrected prior to the intended loss of function of the

components. All issues related to RAI 3.3-3 are resolved.

Moisture Control in Compressed Air for Diesel Generator Systems (RAI 3.3-4)

LRA Tables 3.3.2-3 and 3.3.2.4 for the emergency diesel generator system and the alternate

AC diesel generator system identify treated air and untreated air as an environment for various

components in these systems. It is understood that the portions of these systems with treated

and untreated air are the starting air subsystems normally containing compressed air.

Compressed air systems are susceptible to loss of material due to internal condensation,

unless effective measures are provided to remove moisture. Identify any specific operating

practices used to remove moisture such as the continuous use of air driers or manually draining

air receivers. Also provide justification that the loss of material in the starting air subsystems

containing either treated air or untreated air is effectively managed. For example, identify

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specific operating experience including internal inspection results at susceptible locations.

By letter dated June 21, 2004, the applicant responded by providing the following information:

The starting air for the AAC diesel in table 3.3.2-4 is specified as treated air since the

system contains air dryers. In Table3.3.2-3 for the EDG, the air is identified as

untreated air since there are no air'dryers on the system. However, the starting air -

tanks on the EDGs are drained every month. Loss of material in the starting air system

for the MC diesel will be managed thru'the use of periodic maintenance that ensures

the proper operation of the air dryers such that significant moisture will not be entrained

in the portion of the system that is subject to aging management review. In the starting

air system for the EDGs, loss of material will be managed through periodic inspections

of the internals of components of the starting air system. As indicated in Table 3.3.2-3,

the air receiver tanks for the EDGs are included in the Wall Thinning Monitoring

Program. The tanks are the most susceptible locations for loss of material caused by

moisture in the system. The operating experience review performed as part of the aging

management review did not identify instances of significant corrosion or degradation of

components in the starting air systems for the AAC diesel and EDGs.

In their letter dated June 21, the applicantidentified a specific commitment that loss of material

in the starting air system for the MC diesel will be managed thru the use of periodic

maintenance that ensures the proper operation'of the dryers such that significant moisture will

not be entrained in the portion of the system that is subject to aging management. In the same

letter, the applicant also identified a specific commitment that in the starting air system for the

EDGs, loss of material will be managed through periodic inspections of the internals of

components of the starting air system. ,

Staff Evaluation of the Applicant's Response -

The staff reviewed the applicant's response to RAI 3.3-4. The staff found the applicant's -

response to issues concerning moisture control in compressed air for the diesel generator

systems to be adequate and acceptable because the applicant has identified specific

commitments to manage loss of material in the 'MC diesel and EDGs by providing for periodic

maintenance of the MC air dryers and periodic inspections of the internals of the EDG starting

air system.' The applicant has also performed an operating experience review to confirm that

significant corrosion or degradation was not occurring in the starting air systems..,

-n ...3 ', A .

Bolting Integrity in Auxiliary Systems (RAI 3.3-6)

LRA Tables 3.3.2-3, 3.3.2-4 and 3.3.2-7 identify carbon steel bolting in auxiliary systems as

subject to loss of mechanical closure integrity and the bolting and torquing activities AMP is

credited with managing this aging effect. Note E is applicable to these components and this

note states that this is consistent with NUREG-1 801 material, environment, and aging effect but

a different aging management program is credited. LRA AMP B.1.2, bolting and torquing

activities, indicates that this program relies on industry recommendations for comprehensive

bolting maintenance based on EPRI TR-104213. EPRI report TR-1 04213 is also referenced in

the GALL XI.M1 8 bolting integrity AMP. For those auxiliary systems with carbon steel bolting

associated with Note E, the applicant was requested to clarify if the credited bolting and

torquing activities combined with other inspections required by the system walkdown are

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consistent with the GALL AMP XI.M1 8 bolting integrity, including periodic inspection of closure

bolting for indication of loss of preload with subsequent loss of mechanical closure integrity. If

not consistent, the applicant was requested to identify specific exceptions to the GALL AMP

and the technical justification for the exceptions.

By letter dated June 21, 2004, the applicant stated that the program described in NUREG-1801,

Section XL.M18 covers all bolting within the scope of license renewal including safety-related

bolting, bolting for nuclear steam supply system component supports, bolting for other pressure

retaining components, and structural bolting. It includes periodic inspection of closure bolting

for many aging effects, including loss of preload, cracking, and loss of material. Cracking of

non-Class 1 stainless steel bolting is not an aging effect requiring management and loss of

material is managed by other programs listed in the LRA. Thus, the plant specific Bolting and

Torquing Activities Program, used only to manage loss of mechanical closure integrity, is not

comparable to the aging management program XI.M1 8 of NUREG-1 801. In Appendix B of the

LRA, the ten attributes of the program were provided to allow for its assessment independent of

NUREG-1801 Section XI.M18.

The applicant stated that the System Walkdown Program adequately manages loss of material

for closure bolting as described in LRA Section B.1.28. The Bolting and Torquing Activities

Program and System Walkdown Program also manage loss of mechanical closure integrity for

closure bolting as described in LRA Sections B.1.2 and B.1.28. Visual inspections of bolting for

loss of material and loss of mechanical closure integrity in the System Walkdown Program are

adequate to assure that the closure bolting can perform its intended function since loss of

material (and ultimately loss of mechanical closure integrity) for external surfaces is a long term

aging effect that would be observed well before aging progressed to the point of loss of

intended function. The Bolting and Torquing Activities Program assures that proper torque

values are applied to bolted closures such that loss of mechanical closure integrity as a result of

loss of preload due to high temperatures or significant vibration does not occur.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-6. The staff found the applicant's

response to issues concerning bolting integrity for auxiliary systems to be adequate and

acceptable because the applicant credits more than one program to manage aging effects

pertaining to bolting integrity. The System Walkdown Program manages loss of material. The

Bolting and Torqing Activities Program manages loss of mechanical closure integrity, including

loss of preload. The applicant identified that cracking of non-Class 1 stainless steel bolting is

not an aging effect requiring management. This position is consistent with industry experience

on the basis of bolting and torquing programs developed in accordance with EPRI guidance.

Although the applicant indicated that their Bolting and Torqing Activites Program is not

comparable to the aging management program XI.M1 8 of NUREG-1 801, a combination of the

Bolting and Torqing Activites Program and the System Walkdown Program manage appropriate

aging effects concerning bolting integrity. In addition, NUREG-1 801 Appendix XI.M1 8, states

that the bolting integrity programs developed and implemented in accordance with

commitments made in response to NRC communications on bolting events have provided an

effective means of ensuring bolting reliability.

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3.3.2.3.1 Spent Fuel Pool System -

Summary of Technical Information in the Application

In Section 3.3.2.1.1 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the spent fuel pool system components:

* Boric Acid Corrosion Prevention Program

* System Walkdown Program

* - Water Chemistry Control Program . -

In Table 3.3.2-1 of the LRA, the applicant summarized the AMRs for the spent fuel pool system

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.3.2-1 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the spent fuel pool system component groups.

The staff reviewed the AMR of the spent fuel pool system component/material/environmentl

AERM combinations that are not addressed in the GALL report and specific combinations

addressed in the GALL report within the scope of technical review. Component AERM

combinations not addressed in the GALL report use note F through J in LRA Table 3.3.2-1.

The staff confirmed that the applicant has identified all applicable AERMs and has credited

appropriate AMPs for managing the AERMs& JThe staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Apinq Effects -

Table 2.3.3-1 of the LRA lists individual system components within the scope of license renewal

and subject to aging management review. The component types that do not rely on the GALL

report for AMR include bolting, fuel transfer tube, piping, spent fuel racks, and valves.

For these component types, the applicant identifies the following materials, environments, and

AERMs:

* Stainless steel components subjected to treated borated water (internal and external)

environments are subject to the aging effects of loss of material.,

* Stainless steel components exposed to inside air (internal and external) environments

experience no aging effect.

* Carbon steel bolting exposed to air and managed by the Boric Acid Corrosion

Prevention Program is subject to loss of material.

The staff reviewed the information in Section 2.3.3.1, Table 2.3.3-1, Section 3.3.2.1.1, and

Table 3.3.2-1 in the LRA. During its review, the staff determined that additional information was

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needed to complete its review. The Requests for Additional Information (RAls) were organized

in two groups, general RAls and system specific RAls. General RAls that are applicable to this

system include RAI 3.3-2.

By letter dated May 5, 2004, the staff requested the applicant to provide additional information

on the issues described in RAI 3.3-2. By letter dated June 21, 2004, the applicant responded to

the RAI. The RAI, applicant responses and the staff's evaluation of the responses are

described in Section 3.3.2.3.0 of this SER.

By the same letter dated May 5, 2004, the staff requested the applicant to provide additional

information on the issues described in the system-specific RAI 3.3.2.4.1-1. By letter dated June

21, 2004, the applicant responded to the RAI. RAI 3.3.2.4.1-1, the responses to this RAI, and

the staff's evaluation of the responses are described below:

RAI 3.3.2.4.1-1

LRA Table 3.3.2-1 identifies that, for stainless steel spent fuel racks in a treated borated water

environment, cracking is an applicable aging effect requiring aging management. The

operating temperature for these environments is not identified. The applicant was requested to

clarify why cracking is not a similarly applicable aging effect requiring aging management for

the stainless steel fuel transfer tubes in a treated borated water environment.

In its response, by letter dated June 21, 2004, the applicant stated that cracking is not an aging

effect requiring management for the stainless steel fuel transfer tube because the treated

borated water temperature is maintained less than the 140OF threshold for cracking from stress

corrosion and intergranular attack. The applicant clarified that, since spent fuel pool

temperature at the spent fuel racks may exceed this threshold, cracking is applicable for the

spent fuel racks.

The staff reviewed the applicant's response and found the response to be adequate and

adequate because the applicant indicated that for the stainless steel fuel transfer tube the

treated borated water temperature is maintained less than the 140OF threshold for cracking from

stress corrosion and intergranular attack for stainless steel components.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI the staff finds the aging effects of the

above spent fuel pool cooling and cleanup system component types that are not addressed in

the GALL report and the specific component types that are within the scope of the technical

review are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects. Therefore, the staff finds

that the applicant has identified the appropriate aging effects for the materials and

environments associated with the above components in the spent fuel pool system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement adequately describes the

program.

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LRA Table 3.3.2-1 identifies the following AMPs for managing the aging effects described

above for the spent fuel pool system component types:

* Boric Acid Corrosion Prevention Program (Appendix B.1.3)

* System Walkdown Program (Appendix B.1.28)

* Water Chemistry Control Program (Appendix B.1.30)

The staff's detailed review of these. AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.9, and

3.0.3.3.11 of this SER, respectively.

The Water Chemistry Control Program is credited for managing loss of material aging effect on

the stainless steel components exposed to treated borated water. During its review, the staff

determined that additional information was needed to complete its review. The request for

additional information is described in RAI 3.3-2. RAI 3.3-2, the applicant's response to this RAI

and the staff's evaluation of the responses are described in Section 3.3.2.3.0 of this SER.

The applicant proposed to manage loss of material for stainless steel and nickel-based alloy

components exposed to treated, borated water by using only the Primary and Secondary Water

Chemistry Control Program (AMP B.1.30.3).- The applicant stated that stainless steel

components to be managed this way include heat exchanger tubes, orifices, piping, pump

casings, thermowells, tubing, and valves. The Water Chemistry Control Program will also

-manage nozzles made of nickel-based alloy components and the stainless steel cladding of a

tank made of carbon steel. The staff reviewed the Primary and Secondary Water Chemistry

Control Program and concludes that it is acceptable. Section 3.0.3.1 of this SER documents its

evaluation.

The staff reviewed stainless steel and nickel-based alloy components exposed to treated,

borated water. The staff concludes that since the effects of pitting and crevice corrosion on

stainless steel and nickel-based alloy components are not significant in chemically treated

borated water, inspection of selected components to determine the absence of loss of material

is not required. Because the Primary and Secondary Water Chemistry Control Program is

consistent with the GALL Report, the staff finds this acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds the applicant has identified

appropriate AMPs for managing the aging effects of the spent fuel pool system component:

types that are not addressed by the GALL Report and those specific component types

addressed in the GALL Report that are within the scope of the technical review. In addition, the

staff finds the program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the spent fuel pool

components that are not addressed by the GALL Report and those specific component types

within the scope of the technical review, so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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The staff also reviewed the applicable UFSAR Supplement program descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.2 Water Suppression Fire Protection System

Summary of Technical Information in the Application

Section 2.3.3.2 of this SER describes the water suppression fire protection system. Tables

3.3.1 and 2.3.3-2 identify the passive, long-lived components of this system that are subject to

an AMR. Table 3.3.2-2 provides a summary of the components, aging effects, and AMPs.

Aging Effects

Table 2.3.3-2 of the LRA lists the fire protection components that are within the scope of license

renewal and subject to an AMR. These components include air dryer housing, blower housing,

bolting, ductwork, expansion joint, filter, filter housing, flex hose, gear housing, governor

housing, heat exchanger (housing), heat exchanger (shell), heat exchanger (tubes), heater

housing, nozzle, orifice, pipe/fittings, piping, pump casing, tubing, and valve.

In Section 3.3.2.1.2 and Table 3.3.2-2 of the LRA, the applicant identified the materials,

environments, and aging effects requiring management. The materials identified are aluminum,

carbon steel, cast iron, cast iron with enameline, copper, copper alloys, elastomers, and

stainless steel.

The applicant identified the environment to which these materials could be exposed as air,

exhaust gas, lube oil, fresh raw water, soil, and treated water.

The applicant identified changes in material properties, cracking, fatigue cracking, fouling, loss

of material, wear, and loss of mechanical closure integrity as the aging effects associated with

the fire protection system components.

Aging Management Programs

The LRA identifies the following programs that manage the aging effects related to the fire

protection system:

* Bolting and Torquing Activities Program (Appendix B.1.2)

* Buried Piping Inspection Program (Appendix B.1.4)

* Fire Protection Program (Appendix B.1.10)

* Oil Analysis Program (Appendix B.1.17)

* System Walkdown Program (B.1.28)

Appendix B to the LRA describes these AMPs. The applicant indicated that these AMPs will

adequately manage the effects of aging associated with the components of the fire protection

system during the period of extended operation.

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Staff Evaluation

The staff reviewed Table 3.3.2-2 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the water suppression fire protection system component groups.:

Aging Effects

The staff reviewed the LRA to determine whether the applicant had demonstrated that the

effects of aging for the fire protection system'will be adequately managed during the period of

extended operation, as required by 10 CFR 54;21 (a)(3). The staff reviewed Section 3.3.2.1.2

and Tables 3.3.1 and 3.3.2-2 of the LRA for completeness, consistency with the GALL Report,

and industry experience.

For these component types, the applicant identifies the following materials, environments, and

AERMs:

* Stainless steel components subjected to air (external) and fresh raw water (internal)

environments are subject to the aging effects of loss of material.

* Stainless steel components exposed to inside air (external) environments are subject to

the aging effects of loss of mechanical closure integrity.

* Stainless steel components subjected to fresh raw water (external) environments are

subject to the aging effects of loss of material

* Carbon steel bolting exposed to air and managed by the Boric Acid Corrosion

Prevention Program is subject to loss of mechanical closure integrity.

* Carbon steel components exposed to air (internal and external) and exhaust gas

(internal) environments are subject'to loss of material.

* Carbon steel components exposed to air (internal and external) and exhaust gas

(internal) environments are subject to loss of material.

* Carbon steel components exposed to soil (external) environments are subject to loss of

material.

* Carbon steel components exposed to treated water (internal) environments are subject

to loss of material.

* Carbon steel components exposed to lube oil (internal) environments are subject to loss

of material.

* Cast iron components exposed to treated water (internal) and air (external)

environments are 'subject to loss of material.

* Elastomer components exposed to air (external) and exhaust gas (internal)

environments are subject to change in material properties and cracking.

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* Copper alloy components exposed to fresh raw water (internal) environments are

subject to loss of material.

* Copper alloy components exposed to treated water (internal) environments are subject

to fouling.

LRA Table 3.3.1, Item 3.3.1-30, addresses fire barriers and references Section 3.5.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects resulting from contact of the fire protection system components with the environments

described in Table 3.3.2-2 of the LRA are consistent with the GALL Report and industry

experience for these combinations of materials and environments. Therefore, the staff finds

that the applicant identified the applicable aging effects and associated AMPs that are

appropriate for the combination of materials and environments listed.

Aging Management Programs

The applicant credits the following AMPs with managing the aging effects in the fire protection

system:

* Bolting and Torquing Activities Program (Appendix B.1.2)

* Buried Piping Inspection Program (Appendix B.1.4)

* Fire Protection Program (Appendix B.1.10)

* Oil Analysis Program (Appendix B.1.17)

* System Walkdown Program (Appendix B.1.28)

These AMPs are credited with managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them acceptable for managing the aging effects identified for this

system. These AMPs are evaluated in sections 3.0.3.3.2, 3.0.3.2.2, 3.0.3.2.5, 3.0.3.3.6, and

3.0.3.3.9, respectively, of this SER.

During the onsite audit, the staff asked the applicant to provide the technical basis for treating

cast iron components (i.e., filter housing, heat exchanger housing, diesel engine cooling water

subsystem components, and valves) in a manner similar to carbon steel components. The

applicant's position is that the aging effects are the same in this environment for carbon steel

and cast iron that is not gray cast iron. a The staff finds that using an AMP considered

acceptable to manage the aging effects of carbon steel components is appropriate for cast iron

components.

Additionally, the applicant stated that the aging effects for carbon steel and gray cast iron are

the same, except gray cast iron is susceptible to selective leaching. By letter dated March 24,

2004, the applicant stated that where selective leaching is possible, an additional program is

credited unless the one specified program will manage selective leaching (such as the Diesel

Fuel Monitoring and Oil Analysis Programs). Selective leaching does not normally occur in air,

lube oil, or fuel oil because the environment is not aqueous. In LRA Table 3.3.1, Item Number

3.3.1-29, the applicant stated that gray cast iron components exposed to an environment

conducive to selective leaching are managed by the Periodic Surveillance and Preventive

Maintenance Program, Service Water Integrity Program, or Fire Protection Program that

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includes the management of loss of material due to selective leaching. -Because these

programs manage the aging effects of selective leaching for gray cast iron components, the

staff finds this acceptable.

The applicant's reference to the GALL Report, Volume 2, Item VII.H2.1 -a, for copper-alloy valve

components in treated water did not match the material, aging effect, and program cited. By

letter dated March 24, 2004, the applicant stated that reference to GALL Item VII.H2.1-a is not

appropriate for "valve," and the correct note is 301 rather than "E" in Table 3.3.2-2 of the LRA

(page 3.343 of the LRA).

The staff reviewed the applicant's response and finds that the applicant has demonstrated that

it will adequately manage the effects of aging so that the intended functions will be maintained

consistent with the CLB during the period of extended operation.

In Table 3.3.2-2 of the LRA (page 3.3-43), the applicant proposed to manage loss of material of

copper-alloy valves exposed to lube oil using the Oil Analysis Program (AMP, B.1.17).> Loss of

material because of pitting corrosion is an applicable aging effect for copper-all6y materials in a

lubricating oil environment at locations containing oxygenated water with contaminants such as

halide ions, particularly chloride ions. In addition, loss of material due to galvanic corrosion in a

lubricating oil environment can occur only when materials with different electrochemical

potentials are in contact in the presence of water. Loss of material due to crevice corrosion can

also occur in brass, bronze, and copper materials in a lubricating oil environment at locations,

containing oxygenated water. Oxygen is required for the initiation of crevice corrosion. Lube oil

that is not contaminated with water does not contain oxygen in sufficient quantities for crevice

corrosion to occur.

Water contamination of lubricating oil can occur and is required for the introduction of oxygen'.

However, only high-quality (water- and contaminant-free) lubricating oil is received, and periodic

sampling is performed to ensure the quality is maintained.

Loss of material due to microbiologically influenced corrosion (MIC) is an applicable aging effect

for brass and copper materials exposed to lubricating oil. The applicant treated the lubricating

oil with biocides to limit the presence of microbiological organisms and, therefore, MIC has not

*been a concern for those portions of the water suppression fire protection system that are

within the scope of license renewal and the associated materials exposed to lubricating oil.

On the basis of its review of the information provided by the applicant, the staff concludes that

the applicant has credited the appropriate AMP with managing the aging effects from the

materials and environments associated with the fire protection system and that the AMPs

identified above will effectively manage these aging effects.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the water suppression

fire protection components that are not addressed by the GALL Report and those specific

component types within the scope of the technical review, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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The staff also reviewed the applicable UFSAR Supplement program descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.3 Emergency Diesel Generator System

Summary of Technical Information in the Application

In Section 3.3.2.1.3 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the emergency diesel generator components:

* Bolting and Torquing Activities Program

* Wall Thinning Monitoring Program

* Heat Exchanger Monitoring Program

* Oil Analysis Program

* System Walkdown Program

* Periodic Surveillance and Preventive Maintenance Program

* Service Water Integrity Program

* Water Chemistry Control Program

In Table 3.3.2-3 of the LRA, the applicant provided a summary of AMRs for the emergency

diesel generator system components and identified which AMRs it considered to be consistent

with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.3.2-3 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the Emergency diesel generator system component groups.

The staff reviewed the AMR of the emergency diesel generator component/material/

environment/AERM combinations that are not addressed in the GALL report and specific

combinations addressed in the GALL report within the scope of the technical review.

Component AERM combinations not addressed in the GALL report use note F through J in LRA

Table 3.3.2-3. Material and environment combinations addressed in GALL without a

comparable component use note 301. The staff determined that the applicant has identified all

applicable AERMs and has credited appropriate AMPs for managing the AERMs. The staff

also reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs.

Apinq Effects

Table 2.3.3-3 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The components that do not rely on the GALL Report for AMR include

blower housing, bolting, booster housing, ejector, expansion joint; filter, filter housing, flex hose,

governor house, heat exchanger shell, heat exchanger tubes, heat exchanger tubesheet,

heater housing, piping, pump casing, silencer, tank, thermowell, tubing, unloader, and valve.

For these component types, the applicant identifies the following materials, environments, and

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AERMs:

* Elastomer components exposed to inside and outdoor air, untreated air, or a treated

water environment are subject to the aging effects of change in material properties and

cracking.

* Carbon steel, cast iron, copper alloy, and stainless steel components exposed to the

lube oil environment are subject to the loss of material aging effect.

* Stainless steel and copper alloy components exposed to air or outdoor air experience no

aging effects.

* Carbon steel components exposed to exhaust gas are subject to loss of material and

cracking-fatigue aging effect.

* Carbon steel components exposed to outdoor air and untreated air are subject to

cracking-fatigue aging effects.

* Stainless steel components exposed to exhaust gas are subject to loss of material,

cracking, and cracking-fatigue.-

* Copper alloy and stainless steel components exposed to untreated air are subject to the

aging effects of loss of material and cracking-fatigue.

* Stainless steel components exposed to treated water are subject to loss of material and

cracking. --

* Carbon steel, cast iron, and copper alloy, components exposed to treated water are

subject to the aging effect of loss of material.

* Copper alloy heat exchanger tubes, tubesheets, copper with aluminum fin exposed to

fresh raw water, lube oil, or outdoor air are subject to loss of heat transfer function due

to fouling.

* Carbon steel bolting exposed to air and managed by the Bolting and Torquing Activities

AMP is subject to loss of mechanical closure integrity.

The staff reviewed the information in Section 2.3.3.3, Table 2.3.3-3, Section 3.3.2.1.3, and

Table 3.3.2-3 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized in two groups, general RAls and system specific RAls.

General RAls that are applicable to this system include RAIs 3.3-2, 3.3-3, 3.3-4 and 3.3-6.

By letter dated May 5, 2004, the staff asked the applicant for additional information on the

issues described in RAls 3.3-2, 3.3-3, and 3.3-4. By letter dated May 25; 2004, the staff

requested additional information on the issues described in RAI 3.3-6. By letter dated June 21,

2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes the RAls,

the applicant's responses, and the staff's evaluation of the responses. -

By the same letter dated May 5,2004, the staff asked the applicant to provide additional

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information on the issues described in the system-specific RAls 3.3.2.4.3-1 and 3.3.2.4.3-2. By

letter dated June 21, 2004, the applicant responded to these RAls. The following sections

describe RAIs 3.3.2.4.3-1 and 3.3.2.4.3-2, the responses to these RAls, and the staff's

evaluation of the responses.

RAI 3.3.2.4.3-1

Loss of material due to wear is an applicable aging effect on expansion joints and flex hose.

However, in Table 3.3.2-3 of the LRA, the applicant did not identify this aging effect/aging

mechanism for the expansion joints and flex hose made of elastomer material or stainless steel.

The staff asked the applicant to justify why it did not identify this aging effect/mechanism as an

applicable aging effect on the elastomer or stainless steel expansion joints.

In its response, by letter dated June 21, 2004, the applicant stated that there is no relative

motion between these components and another surface. The applicant also stated that these

components are exposed to environments which do not contain abrasive particles. The

applicant concluded that, as a result, loss of material due to wear is not an aging effect

requiring management for these components.

The staff reviewed the applicant's response and found the response to be acceptable and

adequate because expansion joints will not be subjected to conditions that would result in wear.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects of the emergency diesel generator component types that are not addressed by the

GALL Report and specific component types within the scope of the technical review are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

above components in the emergency diesel generator.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-3 of the LRA identifies the following AMPs for managing the aging effects described

above for the emergency diesel generator:

* Heat Exchanger Monitoring Program (Appendix B.1.12)

* Oil Analysis Program (Appendix B.1.17)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Service Water Integrity Program (Appendix B.1.24)

* Water Chemistry Control Program (Appendix B.1.30)

* Bolting and Torquing Activities Program (Appendix 6.1.2)

* TLAA-Metal Fatigue Program (4.3)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.3, 3.0.3.3.6, 3.0.3.3.7,

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3.0.3.2.7, 3.0.3.2.8, and 3.0.3.3.2 of this SER,! respectively. Section 4.3 of this SER contains

the staff's evaluation of the TLAA-Metal Fatigue Program. .

The Water Chemistry Control Program is credited for managing aging effects on the stainless

steel and copper components exposed to treated water. During its review, the staff determined

that additional information was needed to complete its review. The request for additional

information is described in RAI 3.3-2. RAI 3.3-2, the applicant's response to this RAI and the

staff's evaluation of the responses are described in Section 3.3.2.3.0 of this SER.

The PSPM is credited with managing flex hose exposed to an internal treated water and

untreated air. During its review, the staff determined that additional information was needed to

complete its review. The request for additional information is described in RAI 3.3-3. RAI 3.3-.

3, the applicant's response to this RAI and the staff's evaluation of the response is described in

Section 3.3.2.3.0 of this SER.

The PSPM is credited with managing various'components exposed to untreated air. During its.

'review, the staff determined that additional information was needed to complete its review.. The

request for additional information is described in RAI 3.3-4. RAI 3.3-4, the applicant's response

to this RAI and the staff's evaluation of the response is described in Section 3.3.2.3.0 of this;

SER.

RAI 3.3.2.4.3-2

LRA Table'3.3.2-3 states that carbon and stainless steel expansion joints exposed to an

internal exhaust gas environment is managed by the TLAA-Metal Fatigue Program and the

Periodic Surveillance and Preventive Maintenance Program. The applicant was requested to

explain why the Wall Thinning Program was not applied to the carbon and stainless steel

expansion joints.' The applicant was also requested to identify and justify the frequency of

inspection and clarify if inspections will include internal inspections for cracking and loss of

material as recommended in industry standards-.;--.--

In its response by letter dated June 21; 2004, the applicant stated that expansion joints will be

inspected every 18 months in accordance with vendor recommendations. The applicant also

confirmed that internal inspections and NDE capable of detecting both loss of material and

cracking will be performed. The applicant identified a specific commitment that the wall thinning

program will include the exhaust expansion joints.''

The staff reviewed the applicant response and found the response to be acceptable and

adequate'because the expansion joints will be inspected every 18 months in accordance with:

vendor recommendations and the wall thinninrg program will use NDE to detect loss of material

and cracking. ' - -

During the audit, the staff asked the applicant to justify, for emergency diesel generator heat

exchanger shell component types in LRA Table 3.3.2-3 that are consistent with the GALL

Report, that the aging management program applied to carbon steel remains applicable to cast

iron with a similar environment. -, .

By letter dated March 24, 2004, the applicant stated that where selective leaching is possible,

an additional program is credited unless the one specified program will manage selective

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leaching such as the diesel fuel monitoring and oil analysis programs. Selective leaching does

not normally occur in air, lube oil, or fuel oil due to the lack of an aqueous environment. In its

response, the applicant further stated that if cast iron components are gray cast iron and are

exposed to an environment conducive to selective leaching, then they are managed by a

periodic surveillance and preventive maintenance program, service water integrity program, or

fire protection program that includes the management of loss of material due to selective

leaching. On the basis that these programs manage the aging effects of selective leaching for

gray cast iron components, the staff finds this acceptable.

The applicant credited the PSPM (AMP B.1.18) and not the service water integrity program

(AMP B.1.24) for managing loss of material for components exposed to a raw water

environment. The applicant agreed to add the service water integrity program for these

components. By letter dated March 24, 2004, the applicant stated that the PSPM program

manages loss of material for the emergency diesel generator heat exchanger bonnet in fresh

raw water (page 3.3-51 of the LRA) through periodic internal inspections during emergency

diesel generator overhauls. In addition to the PSPM program, the service water integrity

program is conservatively included as a program since it provides additional aging management

of this component. On the basis that these programs manage the aging effects of loss of

material for components exposed to a raw water environment, the staff finds this acceptable.

The applicant credited the PSPM (AMP B.1.18) and not the auxiliary systems water chemistry

control program (AMP B.1.30.1) for managing loss of material for components internally

exposed to a treated-water environment. The applicant agreed that the auxiliary water

chemistry control program should have been credited for bonnet and shell components

internally exposed to a treated water environment, which is acceptable to the staff. By letter

dated March 24, 2004, the applicant stated that the auxiliary systems water chemistry control

program applies to the emergency diesel generator heat exchanger bonnet and shell in treated

water (page 3.3-51 of the LRA) rather than the PSPM program. On the basis that this program

manages the aging effects of loss of material for components internally exposed to a treated

water environment, the staff finds this acceptable.

The applicant credited the auxiliary systems water chemistry control program (AMP B.1.30.1) to

manage loss of material of carbon steel heater housing and orifice, carbon and stainless steel

piping, emergency diesel generator pump casing and tank, tubing, and valves in an internally

treated water environment. This is consistent with Item VII.H2.1-a of the GALL Report with a

different AMP credited than the GALL AMP XI.M21, closed-cycle cooling water system. If this

is the case, LRA Note D should be changed to LRA Note E. By letter dated March 24, 2004,

the applicant stated that reference to LRA Note D is not appropriate for the emergency diesel

generator heater housing and orifice (page 3.3-54 of the LRA), the carbon and stainless steel

piping (page 3.3-56 of the LRA), the emergency diesel generator pump casing and tank -

(page 3.3-57 of the LRA), tubing (page 3.3-59 of the LRA), and valve (page 3.3-61 of the LRA)

in treated water. The correct note is LRA Note E. The staff finds the applicant's response

acceptable and consistent with the LRA Notes.

In the case of a copper-alloy lubricator housing exposed to air, the applicant identified no aging

effect. On the basis of the staff's evaluation that copper-alloy components exposed to air have

no aging effects, the staff concludes that this is acceptable.

On the basis of its review of the information provided in the LRA, the staff finds that the

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applicant has identified appropriate AMPs for managing the aging effects of the emergency

diesel generator component types that are not addressed by the GALL Report and those

specific component types addressed by the GALL Report that are within the scope of the.

technical review. In addition, the staff finds the program descriptions in the UFSAR Supplement

acceptable. -a

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the emergency diesel

generator components that are not addressed by-the GALL Report and those specific. --

component types within the scope of the technical review, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by i 0 CFR

54.21 (a)(3).

The staff also reviewed the applicable UFSAR Supplement program descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.4 Alternate AC Diesel Generator System

Summary of Technical Information in the AgDlication

InSection 3.3.2.1.4 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the alternate ac diesel generator system components:

* Bolting and Torquing Activities Program

* Wall Thinning Monitoring Program

* Oil Analysis Program

* System Walkdown Program

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control Program

In Table 3.3.2-4 of the LRA, the applicant summarized the AMRs for the alternate ac diesel

generator system components and identified which AMRs it considered to be consistent with

the GALL Report. - * 'r,.

Staff Evaluation

The staff reviewed Table 3.3.2-4 of the LRA,' which summarized the results of AMR evaluations

in the SRP-LR for the alternate ac diesel generator system component groups. * . .* - * ;

The staff also reviewed the AMR of the alternate AC diesel generator system component/

materiaVenvironment/AERM combinations'thatare not addressed in the GALL report and

specific combinations that are -addressed in the GALL report within the scope of the technical

review. Component AERM combinations not addressed in the GALL report use note F through

J in LRA Table 3.3.2-4. Material and environment combinations addressed in GALL without a

comparable component use note 301. The staff confirmed that the applicant has identified all

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applicable AERMs and has credited appropriate AMPs for managing the AERMs. The staff

also reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs. During the staff evaluation of the LRA, the

applicant's response to RAI 2.3.3.3.4-1 identified thermal insulation around the exhaust piping

was added to the scope of components subject to an AMR.

Aging Effects

Table 2.3.3-4 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include blower housing, bolting, expansion joint, filter, filter housing, flex hose, governor

housing, heat exchanger (shell), heat exchanger (tubes), heater housing, indicator housing,

lubricator housing, orifice, piping, pump casing, silencer, thermowell, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components in an exhaust gas environment are subject to loss of

material. In the same environment, carbon steel and stainless steel components

experience cracking-fatigue, and stainless steel components are subject to the

additional aging effect of cracking.

* In a lube oil environment, carbon steel, carbon steel with aluminum fins, copper alloy,

and stainless steel components are subject to loss of material. Fouling is an applicable

aging effect for carbon steel with aluminum fins and copper alloy components in lube oil.

Cracking is an applicable aging effect in a lube oil environment for elastomer and

stainless steel. Elastomer components in a lube oil environment are subject to the

additional aging effect of change of material properties.

* Carbon steel, copper alloy, and stainless steel components are subject to loss of

material in a treated air environment, and stainless steel components in the same

environment may experience the additional aging effect of cracking.

* In a treated water environment, carbon steel, copper alloy, and stainless steel

components are subject to loss of material. In the same environment, carbon steel with

aluminum fins and copper alloy components experience fouling. Also in a treated water

environment, elastomer components are subject to cracking and change in material

properties. Cracking is also applicable to stainless steel components in the treated

water environment.

* In outdoor air, carbon steel with aluminum fins experiences fouling, and copper alloy

components suffer from fouling, as well as loss of materials through wear. In an air

environment, aluminum, copper alloy, glass, and stainless steel components experience

no applicable aging effects. Carbon steel blower housings exposed to outdoor air are

subject to cracking-fatigue. Carbon steel bolting managed by the Bolting and Torquing

Activities Program is subject to loss of mechanical closure integrity.

* Neither glass components in treated water nor stainless steel components in outdoor air

experience aging effects.

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The staff reviewed the information in Section 2.3.3.4, Table 2.3.3-4, Section 3.3.2.1.4, and

Table 3.3.2-4 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized in two groups, general RAls and system specific RAls.-

General RAls that are applicable to this system include RAls 3.3-2, 3.3-3, 3.3-4 and 3.3-6.

By letter dated May 5, 2004, the staff requested the applicant to provide additional information

on the issues described in RAls 3.3-2, 3.3-3, 3.3-4 and 3.3-6. By letter dated May 25,2004, the

staff requested the applicant to provide additional information on the issues described in RAls

3.3-6. By letters dated June 21,2004, the applicant responded to these RAls. The RAls, the

applicant's responses and the staff's review of the responses are described in Section 3.3.2.3.0

of this SER.

By a letter dated May 5, 2004, the staff asked the applicant to provide additional information on

the issues described in the system-specific RAI 3.3.2.4.1-1. By letter dated June 21, 2004, the

applicant responded to that RAI. The following section describes RAI 3.3.2.4.1-1, the

applicant's response, and the staff's evaluation of the response.

RAI 3.3.2.4.1 -1

Table 3.3.2-4 of the LRA credits the Periodic Surveillance and Preventive Maintenance

Program with managing fouling in heat exchanger tubes. A periodic diesel generator test alone

may not be adequate verification that the required heat transfer is maintained under all

applicable design conditions. The staff asked the applicant to clarify how the inspections and

testing are performed to ensure that fouling does not adversely affect heat transfer by using

proven practices such as periodic heat balances to specific industry standards.

In its response, the applicant stated that the alternate ac diesel is operated on a quarterly basis

for at least 2 hours at near full-rated load, and full-rated load significantly exceeds the required

design loading of the diesel. The applicant also stated that during this testing, engine

parameters such as inlet and outlet temperatures on heat exchangers are monitored and

trended to assure that the heat exchangers are capable of removing heat loads. The applicant

further stated that adverse trends or alarms noted during performance of the surveillance tests

would be identified in accordance with the Corrective Action Program. The applicant concluded

that appropriate actions to determine the cause and correct the condition would be taken long

before the intended function of the system is affected.

The staff reviewed the applicant's response and found the response to be acceptable and

adequate because the applicant indicated that (1) the alternate ac diesel is tested on a

quarterly basis for at least 2 hours at near full-rated load which significantly exceeds the

required design loading of the diesel, (2) during this testing, engine parameters such as inlet

and outlet temperatures on heat exchangers are monitored and trended, and (3) any adverse

trends or alarms noted would lead to appropriate actions being taken to determine the cause

and to correct the condition long before the intended function of the system is affected.

As a result of the resolution of an unresolved issue related to RAI 2.3.3.4-1 during the scoping.

and screening review, the thermal insulation forthe exhaust piping for the EDG was placed in

the scope to license renewal and subject to an aging management review. The staff requested

that the applicant identify the type of thermal insulation used on the exhaust piping and to

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review the applicability of NRC Information Notice 88-28 regarding the type of insulation.

By letter dated September 24, 2004, the applicant clarified that two types of insulation material

cover the alternate AC generator exhaust piping in the generator building. The applicant

identified that the majority of the insulation is calcium silicate with metal jacketing and a small

portion is fiberglass blanket material encased in a covering. The applicant stated that no aging

effects requiring management have been identified for the exhaust piping insulation in its dry,

indoor environment. By e-mail from the PM dated September 23, 2004; additional information

was forwarded by the applicant. The applicant clarified that a walkdown of the insulation did not

detect any foil covering on the blanket insulation similar to that reported in NRC IN 88-28.

The staff reviewed the applicant's responses and found the responses to be acceptable and

adequate because the type of insulation used in this application is not subjected to

environmental conditions that would result in degradation of thermal properties during the

period of extended operation.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds the aging effects of the

above alternate ac diesel generator system component types that are not addressed by the

GALL Report and specific component types that are addressed by the GALL Report and are

within the scope of technical review are consistent with industry experience for these

combinations of materials and environments. The staff did not identify any omitted aging

effects. Therefore, the staff finds that the applicant has identified the appropriate aging effects

for the materials and environments associated with the above components in the alternate ac

diesel generator system.

Aging Manaaement Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-5 of the LRA identifies the following AMPs for managing the aging effects described

above for the alternate ac diesel generator system:

* Wall Thinning Monitoring Program (Appendix B.1.29)

* Oil Analysis Program (Appendix B.1.17)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* System Walkdown Program (Appendix B.1.28)

* Water Chemistry Control Program (Appendix B.1.30)

* Bolting and Torquing Activities Program (Appendix B.1.2)

* TLAA-Metal Fatigue Program (4.3)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.10, 3.0.3.3.6, 3.0.3.3.7,

3.0.3.3.9, 3.0.3.3.11, and 3.0.3.3.2 of this SER, respectively. Section 4.3 of this SER contains

the staff's evaluation of the TLAA-Metal Fatigue Program.

The applicant credits the Water Chemistry Control Program with managing the loss of material

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aging effects on the copper alloy, carbon steel and stainless steel components exposed to

treated water. During its review, the staff determined that it needed additional information and

issued RAI 3.3-2. Section 3.3.2.3.0 of this SER describes RAI 3.3-2, the applicant's response,

and the staff's evaluation of the response..? ' -; -

The applicant credits the PSPM Program With'managing flex hose exposed to an internal

treated water, lube oil and treated air. During its review, the staff determined that it needed

additional information and issued RAI 3.3-3. Section 3.3.2.3.0 of this SER describes RAI 3.3-3,

the applicant's response, and the staff's evaluation of the response.

The applicant credits the PSPM Program with managing various components'exposed to

treated air. During its review, the staff determined that additional information was needed to

complete-its review. The request for additional information is described in RAI 3.3-4. RAI 3.3-

4, the applicant's response to this RAI and the staff's evaluation of the response is described in

Section 3.3.2.3.0 of this SER. - .

By letter dated May 5, 2004, the staff requested the applicant to provide additional information

on the issues described in the system-specific RAI 3.3.2.4.1-1. By letter dated June 21, 2004,

the applicant responded to the RAI. RA1 3.3.2.4.1-1, the responses to this RAI, and the staff's

evaluation of the responses are described below:

RAI 3.3.2.4.4-1

LRA Table 3.3.2-4 credits the Periodic Surveillance and Preventive Maintenance Program for

managing fouling in heat exchanger tubes: A periodic diesel generator test alone may not be

adequate verification that the required heat transfer is maintained under all applicable design

conditions. The applicant was requested to clarify how the inspections and testing are'

performed to ensure that fouling does not adversely affect heat transfer by using proven

practices such as periodic heat balances to specific industry standards.

In its response, by letter dated June 21, 2004, the applicant stated that the AAC diesel is

operated on a quarterly basis for at least two hours at near full-rated load and full-rated load

significantly exceeds the required design loading of the diesel. The applicant also stated that

during this testing, engine parameters such'as inlet and outlet temperatures on heat

exchangers are monitored and trended to'assure the heat exchangers are capable of removing

heat loads. The applicant further stated that adverse trends 'or alarms noted during

performance of the surveillance tests would be identified in accordance with the Corrective

Action Program. The applicant concluded that appropriate actions to determine the cause and

correct the condition would be taken long before the intended function of the system is affected.

The staff reviewed the applicant's response and found the response to be adequate because

the applicant indicated that a) the AAC diesel is' tested on a quarterly basis for at least two:

hours at near full-rated load which significantly 'exceeds the required design loading of the

diesel, b) during this testing, engine parameters such as inlet and outlet temperatures on heat

exchangers are monitored and trended, and that c) any adverse trends or alarms noted would

lead to appropriate actions being taken to determine the cause and to correct the condition long

before the intended function of the system is affected.

During the audit, the staff asked the applicant to provide a technical basis for treating cast iron

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components in the diesel engine cooling water subsystem in a manner similar to carbon steel

components. The applicant's position is that carbon steel and cast iron experience the same

aging effects in this environment. The staff agrees that use of an AMP considered acceptable

for carbon steel is appropriate for these components.

The staff identified a discrepancy in the classification of AMRs involving Water Chemistry

Control Programs. The applicant assigned Notes B and D of the LRA in cases where LRA

Note E is more appropriate. By letter dated March 24, 2004, the applicant stated that reference

to "water chemistry control" for the alternate ac diesel generator stainless steel expansion joint

in treated water (page 3.3-67 of the LRA) in Table 3.3.2-4 means the Auxiliary Systems Water

Chemistry Control Program. In addition, wherever LRA Note B or D appears in Tables 3.3.2-3

and 3.3.2-4 with the Auxiliary Systems Water Chemistry Control Program as an AMP, LRA

Note E should have been used since the Auxiliary Systems Water Chemistry Control Program

is the water chemistry control program for treated water, and it is a plant-specific program.

Based on its review of the applicant's response, the staff finds that these corrections are

consistent with the LRA note classifications and are acceptable.

The staff reviewed the alternate ac diesel generator system stainless steel components

exposed to an air environment. The staff has observed that stainless steel components

exposed to air/gas, containment air, indoor air (not air-conditioned), and outdoor environments

show no aging effect. The GALL Report does not identify an air/gas environment for these

components and materials. The staff finds that no aging effects are applicable, and thus, the

absence of an AMP for stainless steel components exposed to air is acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAls, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the alternate ac diesel generator

system component types that are not addressed by the GALL Report and specific component

types that are addressed in the GALL Report and are within the scope of the technical review.

In addition, the staff finds the program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the alternate ac diesel

generator system components that are not addressed by the GALL Report and those specific

component types within the scope of the technical review, 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.5 Chemical and Volume Control System

Summary of Technical Information in the Application

In Section 3.3.2.1.5 of the LRA, the applicant identified the materials, environments, and aging

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effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the CVCS components:

* Bolting and Torquing Activities Program:

* Boric Acid Corrosion Prevention Program

* Oil Analysis Program

* ,System Walkdown Program .

* Periodic Surveillance and Preventive Maintenance Program

* Water Chemistry Control Program

In Table 3.3.2-5 of the LRA, the applicant summarized the AMRs for the CVCS components

and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.3.2-5 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the CVCS component groups.

The staff reviewed the AMR of the chemical and volume control system component/material!

environment/AERM combinations that are not addressed in the GALL report and specific ;

combinations that are addressed in the GALL report within the scope of the technical review.

Component AERM combinations not addressed in the GALL report use note F through J inLRA Table 3.3.2-5. Material and environment combinations addressed in GALL without a

comparable component use note 301. The staff determined that the applicant has identified all

applicable AERMs and has credited appropriate AMPs for managing the AERMs. The staff

also reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs.

Aaing Effects

Table 2.3.3-5 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bolting, gear housing, heat exchanger (shell, including the heat exchanger channel

head/bonnet), piping, pump casing, sight glass,,sight glass housing, tank, thermowell, tubing,

and valves. Carbon steel bolting managed by the Boric Acid Corrosion Prevention Program

and stainless steel bolting managed by the Bolting and Torquing Activities Program are within

the scope of the technical review. -

For these component types, the applicant identified the following materials, environments, and

AERMs:

* In a treated borated water environment, stainless steel components are subject to loss

of material.

* In a lube oil environment, stainless steel components are subject to cracking and loss of

material. In the same lube oil environment, carbon steel components are subject to loss

of material only, and glass components experience no aging effect.

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* Stainless steel and glass components exposed to an air environment experience no

aging effects.

* Stainless steel components in a nitrogen environment also experience no aging effects.

* Carbon steel and stainless steel bolting exposed to air is subject to loss of mechanical

closure integrity.

* Stainless steel heat exchanger shells, piping, themowells, tubing, and valves exposed to

treated borated water above 132 0C (270 OF) are subject to cracking-fatigue. Stainless

steel pump casings exposed to treated borated water are also subject to crackingfatigue.

The staff reviewed the information in Section 2.3.3.5, Table 2.3.3-5, Section 3.3.2.1.5, and

Table 3.3.2-5 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized into two groups, general RAls and system-specific RAls.

General RAls applicable to this system include RAls 3.3-1 and 3.3-2.

By letter dated May 5, 2004, the staff asked the applicant for additional information on the

issues described in RAIs 3.3-1 and 3.3-2. By letter dated June 21, 2004, the applicant

responded to these RAls. Section 3.3.2.3.0 of this SER describes the RAls, the applicant's

responses, and the staff's evaluation of the responses.

By the same letter dated May 5, 2004, the staff asked for additional information on the issues

described in the system-specific RAI 3.3.2.5.1-1. By letter dated June 21, 2004, the applicant

responded to the RAI. The following section describes RAI 3.3.2.5.1-1, the responses to this

RAI, and the staff's evaluation of the responses.

RAI 3.3.2.4.5-1

For stainless steel components in a treated borated water environment, the staff asked the

applicant to clarify whether loss of fracture toughness/thermal aging embrittlement is an

applicable aging effect. The staff also asked the applicant to provide the technical basis if this

aging effect is not applicable or otherwise specify the applicable AMP.

In its response by letter dated June 21, 2004, the applicant stated that loss of fracture

toughness can occur in cast stainless steel materials exposed to temperatures greater than

250 0C (482 0F). The applicant clarified that components on the tube-side inlet and shell-side

outlet of the regenerative heat exchanger are exposed to temperatures above the threshold, but

none are constructed of cast austenitic stainless steel. The applicant concluded that fracture

toughness is not an aging effect requiring management for CVCS components.

The staff reviewed the applicant's response and found it to be adequate and acceptable

because the applicant indicated that the stainless steel used in the CVCS at temperatures

above 250 0C (482 OF) is not cast austenitic and is therefore not susceptible to loss of fracture

toughness.

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On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAls, the staff finds that the aging effects of

the CVCS component types that are not addressed by the GALL Report and the specific -. -

component types that are addressed in the GALL Report and are within the scope of technical

review are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects. Therefore, the staff finds

that the applicant has identified the appropriate aging effects for the materials and - ;

environments associated with the above components in the CVCS.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects.- The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-5 of the LRA identifies the following AMPs for managing the aging effects described

above for managing the aging effects described above for the CVCS:

* ' Water Chemistry Control Program (Appendix B.1.30)

* Oil Analysis Program (Appendix B.1.17):

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Bolting and Torquing Activities Program (Appendix B.1.2)

* Boric Acid Corrosion Prevention Program (Appendix B.1.3)

* ' TLAA-Metal Fatigue Program (4.3).

The staff's detailed review of these AMPs appears in Sections 3.0.3.1, 3.0.3.3.6, 3.0.3.3.7,

3.0.3.3.2, and 3.0.3.2.1 of this SER, respectively. Section 4.3 of this SER contains the staff's'

evaluation of the TLAA-Metal Fatigue Program.

The applicant credits the Water Chemistry.Control Program with managing the loss of material

aging effect on the stainless steel components exposed to treated borated water. During its

review, the staff determined that it needed additional information and issued RAI 3.3-2.- Section

3.3.2.3.0 of this SER describes RAI 3.3-2, the applicant's response to this RAI, and the staff's

evaluation of the response., - - .

For the CVCS pump casing, the applicant identified cracking-fatigue as an aging effect

managed with the Periodic Surveillance and Pireventive Maintenance Program (AMP B.1.18).

This aging effect is not included in the detection of aging effects program element description in

Appendix B, Section B.1.18, to the LRA. By letter dated March 24, 2004, the applicant statedthat cracking-fatigue is identified as an aging !effect for the CVCS pump casing (page 3.3-84 of

the LRA) in Table 3.3.2-5 with the PSPM Program as an AMP. Cracking-fatigue should be

included as an aging effect for the CVCS charging pumps in the "detection of aging effects".

program element of Appendix B, Section B.1.18, to the LRA. Based on its review of the

applicant's response, the staff finds the correction to the udetection of aging effects" program

element for the PSPM AMP acceptable.

.. . The

The staff reviewed the OVOS stainless steel components exposed to an air environment. The

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staff has observed that stainless steel components exposed to air/gas, containment air, indoor

air (not air-conditioned), and outdoor environments show no aging effect. The GALL Report

does not identify an air/gas environment for these components and materials. The staff finds

that no aging effects are applicable, and thus, the absence of an AMP for stainless steel

components exposed to air is acceptable.

For the management of cracking in the stainless steel regenerative heat exchanger exposed

internally to treated borated water greater than 132 'C (270 'F) (page 3.3-83 of the LRA), the

applicant credited the Water Chemistry Control Program.

The GALL Report, Volume 2, Item VII.E1.7-c, calls for augmentation of water chemistry control

by verification that cracking is absent using temperature and radioactivity monitoring of the

shell-side water and eddy-current testing of tubes. The applicant responded that the heat

exchanger tubes are not required to satisfy the pressure boundary function of the regenerative

heat exchanger. On this basis, the staff finds the response acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the CVCS component types that

are not addressed by the GALL Report and those specific component types addressed in the

GALL Report that are within the scope of the technical review. In addition, the staff finds the

program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the chemical and

volume control system components that are not addressed by the GALL Report and those

specific component types within the scope of the technical review, 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.6 Halon Fire Protection and Reactor Coolant Pump Motor Oil Leakage Collection

System

Summary of Technical Information in the Application

Section 2.3.3.6 of this SER describes the Halon fire protection system and the RCP Motor Oil

Leakage Collection system. Table 2.3.3-6 of the LRA identifies the passive, long-lived

components of this system that are subject to an AMR. Tables 3.3.1 and 3.3.2-6 summarize

the components, aging effects, and AMPs.

Aging Effects

Table 2.3.3.6 of the LRA lists the fire protection components that are within the scope of license

renewal and subject to an AMR. These components include bolting, flex hose, indicator

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housing, nozzle, pan, piping, tank, tubing, and valve.

In Section 3.3.2.1.6 and Table 3.3.2-6 of the LRA, the applicant identified the materials,

environments, and aging effects requiring management. The materials identified are aluminum,

brass, carbon steel, cast bronze, glass, stainless steel, and stainless steel braid with Teflon

liner.

The applicant identified the environments to which these materials could be exposed as air,

Halon 1301, lube oil, nitrogen, and untreated borated water.

The applicant identified loss of material and loss of mechanical closure integrity as the aging

effects associated with the fire protection system components.

Aging Management Programs -

The LRA identifies the following programs that manage the aging effects related to the fire

protection system.

* Boric Acid Corrosion Prevention (Appendix B.1.3)

* Periodic Surveillance and Preventive Maintenance (Appendix B.1.18)

Appendix B to the LRA describes these AMPs. The applicant indicated that these AMPs will

adequately manage the effects of aging associated with the components of the fire protection

system during the period of extended operation.:

Staff Evaluation

The staff reviewed Table 3.3.2-6 of the LRA; which summarized the results of AMR evaluations

in the SRP-LR for the Halon fire protection and RCP motor oil leakage collection system

component groups. : : .. ., . - --

The staff reviewed the LRA to determine whether the applicant demonstrated that it would

adequately manage the effects of aging for the fire protection system during the extended

period of operation, as required by 10 CFR 54.21 (a)(3). The staff reviewed Section 3.3.2.1.6

and Tables 3.3.1 and 3.3.2-6 of the LRA for completeness, consistency with the GALL Report,

and industry experience . -

For these component types, the applicant identifies the following materials, environments, and

AERMs:

* Stainless steel components subjected to untreated borated water (external) and lube oil

(internal) environments are subject to the aging effects of loss of material.

* Carbon steel components exposed to inside air (external) and untreated borated water

(external) environments are subject to the aging effects of loss of material.

* Carbon steel components subjected to'air (external) and lube oil (internal) environments

are subject to the aging effects of loss of material

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* Carbon steel bolting exposed to untreated borated water environment is subject to loss

of mechanical closure integrity.

* Carbon steel components exposed to untreated borated water (internal) environments

are subject to loss of material.

Table 3.3.1 includes the RCP oil collection system under Item 3.3.1-6 and references Section

3.3.2.2.6.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects resulting from contact of the Halon fire protection system components and RCP motor

oil collection system components with the environments described in Table 3.3.2-6 of the LRA

are consistent with the GALL Report and industry experience for these combinations of

materials and environments. Therefore, the staff finds that the applicant identified the

applicable aging effects and associated AMPs, and they are appropriate for the combination of

materials and environments listed.

Aging Management Programs

The applicant credits the following AMPs with managing the aging effects in the Halon fire

protection and RCP motor oil leakage collection system:

* Boric Acid Corrosion Prevention Program (Appendix B.1.3)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

These AMPs are credited with managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them acceptable for managing the aging effects identified for this

system. These AMPs are evaluated in sections 3.0.3.2.1 and 3.0.3.3.7 of this SER.

During the onsite audit, the staff reviewed the stainless steel components of the Halon fire

protection and RCP motor oil leakage collection system that are exposed to an air environment.

The staff has observed that stainless steel components exposed to air/gas, containment air,

indoor air (not air-conditioned), and outdoor environments show no aging effects. The GALL

Report does not identify an air/gas environment for these components and materials. The staff

finds that no aging effects requiring management are applicable, and thus, the absence of an

AMP for stainless steel components exposed to air is acceptable.

On the basis of its review of the information provided by the applicant, the staff concludes that

the applicant has credited the appropriate AMPs with managing the aging effects from the

materials and environments associated with the Halon fire protection system and RCP motor oil

collection system, and that the AMPs identified above will effectively manage these aging

effects.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the spent fuel pool

components that are not addressed by the GALL Report and those specific component types

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within the scope of the technical review, 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.7 Fuel Oil System,

Summary of Technical Information in the Apnlication

In Section 3.3.2.1.7 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the fuel oil system components:

* Bolting and Torquing Activities Program (Appendix B.1.2).

* Buried Piping Inspection Program (Appendix B.1.4)

* Oil Analysis Program (Appendix B.1.17)

* System Walkdown Program (Appendix B.1 .28)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Diesel Fuel Monitoring Program (Appendix B.1.7)

In Table 3.3.2-7 of the LRA, the applicant summarized the AMRs for the fuel oil system

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.3.2-7 of the LRA, which summarized the results of AMR evaluations.

in the SRP-LR for the fuel oil system component groups.

The technical staff reviewed the AMR of the fuel oil system component/materiaVl ;

environment/AERM combinations that are not addressed in the GALL report and specific

combinations addressed in the GALL report within the scope of the technical review.

Component AERM combinations not addressed in GALL use note F through J in LRA Table

3.3.2-7. Material and environment combinations addressed in GALL without a comparable

component use note 301. The staff determined that the applicant has identified all applicable

AERMs and has credited appropriate AMPs for managing the AERMs. The staff also reviewed

the applicable UFSAR supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs. * :

The technical staff reviewed the AMR of the fuel oil system componentlmateriaV environment/

AERM combinations that are not addressed in the GALL Report and specific combinations.

addressed in the GALL Report that are within the scope of the technical review. Component

AERM combinations not addressed in the GALL Report use Notes F through J in LRA Table

3.3.2-7. Material and environment combinations addressed in the GALL Report without a

comparable component use Note 301. The staff determined that the applicant identified all

applicable AERMs and credited appropriate AMPs with managing the AERMs. The staff also

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reviewed the applicable UFSAR Supplements for the AMPs to ensure that the program

descriptions are adequate.

Aging Effects

Table 2.3.3-7 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bolting, filter, filter housing, flame arrestor, flex hose, heat exchanger (tubes), indicator

housing, injector housing, orifice, piping, tank, thermowell, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel, copper alloys, elastomer, and stainless steel components exposed to fuel

oil environment are subject to the aging effects of loss of material. In the same fuel oil

environment, stainless steel and elastomer components are subject to the additional

aging effects of cracking and change of material properties.

* Carbon steel components in air, lube oil, outdoor air, and sand and concrete

environments are subject to loss of material.

* In an outdoor environment, loss of material is an applicable aging effect for carbon steel

with aluminum fin and copper alloy components.

* Copper alloy components in an air environment and aluminum and stainless steel

components exposed to an outdoor air environment experience no applicable aging

effects.

* Carbon steel and stainless steel bolting exposed to air and managed by the Bolting and

Torquing Activities Program is subject to loss of mechanical closure integrity.

The staff reviewed the information in Section 2.3.3.7, Table 2.3.3-7, Section 3.3.2.1.7, and

Table 3.3.2-7 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized in two groups, general RAls and system-specific RAls.

A general RAI applicable to this system is RAI 3.3-3.

By letter dated May 5, 2004, the staff asked the applicant for additional information on the

issues described in RAI 3.3-3. By letter dated May 25, 2004, the staff requested additional

information on the issues described in RAI 3.3-6. By letter dated June 21, 2004, the applicant

responded to the RAls. Section 3.3.2.3.0 of this SER describes the RAI, the applicant's

responses, and the staff's evaluation of the responses.

By the same letter dated May 5, 2004, the staff requested the applicant to provide additional

information on the issues described in the system-specific RAI 3.3.2.4.7-1. By letter dated June

21, 2004, the applicant responded to this RAI. The following section describes RAI 3.3.2.4.7-1,

the responses to this RAI, and the staff's evaluation of the responses.

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RAI 3.3.2.4.7-1

The LRA identifies cracking as an applicable aging effect for some stainless steel components

in a fuel oil environment (such as filter and thermowell) but not others in the same environment

(such as indicator housing and orifice). The staff asked the applicant to clarify the

environments, including temperatures, applicable to stainless steel components in the fuel oil

system to justify the'difference in the identified aging effects.

In its response, by letter dated June 21, 2004, the applicant stated that cracking is identified as

an aging effect requiring management for stainless steel components in fuel oil when the fluid

temperature can exceed 60 OC (140 'F) and there is a potential for water in the oil. The -

applicant clarified that portions of the fuel oil system for the alternate ac diesel, emergency

diesel generator, and fire pump diesel can exceed 60 OC (140 OF) during engine operation. The

applicant further stated that for these portions of the fuel oil system, it identified cracking as an

aging effect for stainless steel components. Finally the applicant stated that stainless steel

components in the remainder of the fuel oil system are not exposed to temperatures in excess

of 600C(140 `F).

The staff reviewed the applicant's response and found it to be acceptable and adequate

because the applicant indicated that portions of the fuel oil system can exceed 60 0C (140 OF)

during engine operation and for these portions of the fuel oil system, cracking was identified as

an aging effect for stainless steel components, while stainless steel components in the

remainder of the fuel oil system are not exposed to temperatures in excess of 60 0C (140 OF).

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAls, the staff finds that the aging effects of

the fuel oil system component types that are not addressed by the GALL Report and those

specific component types addressed in the GALL Report that are within the scope of the:

technical review are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects. Therefore, the staff finds

that the applicant has identified the appropriate aging effects for the materials and

environments associated with the above components of the fuel oil system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-7 of the LRA identifies the following AMPs for managing the aging effects described

above for the fuel oil system: ..;-.

* Diesel Fuel Monitoring Program (Appendix B.1.7)

* System Walkdown Program (Appendix B.1.28)

* Oil Analysis Program (Appendix B.1.17) :---

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1 .18)

* Bolting and Torquing Activities Program-(Appendix B.1.2)

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The staff's detailed review of these AMPs appears in Sections 3.0.3.2.3, 3.0.3.3.9, 3.0.3.3.6,

3.0.3.3.7 and 3.0.3.3.2 of this SER, respectively.

The applicant credits the Periodic Surveillance and Preventive Maintenance Program with

managing flex hose exposed to an internal fuel oil environment. During its review, the staff

determined that it needed additional information and issued RAI 3.3-3. Section 3.3.2.3.0 of this

SER describes RAI 3.3-3, the applicant's response to this RAI, and the staff's evaluation of the

response.

The staff asked the applicant to provide a technical basis for treating cast iron components in

the fuel oil system in a manner similar to carbon steel components. The applicant's position is

that the aging effects for carbon steel and cast iron in this environment are the same. The staff

agrees that use of an AMP considered acceptable for carbon steel is appropriate for these

components.

The applicant credited the System Walkdown Program (AMP B.1.28) with managing the aging

effects of loss of material of heat exchangers (tubes) made of carbon steel with aluminum fins

in external air. In Note 302 of the table, the applicant states that the aging effect applies only to

the carbon steel portion of the component. The staff finds that aluminum is corrosion resistant

in a dry air environment and that there are no applicable aging effects requiring aging

management. On that basis, the staff finds the applicant's position acceptable.

The staff reviewed the fuel oil system stainless steel components exposed to an air

environment. The staff has observed that stainless steel components exposed to air/gas,

containment air, indoor air (not air-conditioned), and outdoor environments show no aging

effects. The GALL Report does not identify an air/gas environment for these components and

materials. The staff finds that no aging effects are applicable, and thus, the absence of an

AMP for stainless steel components exposed to air is acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the fuel oil system component

types that are not addressed by the GALL Report and those specific component types

addressed in the GALL Report that are within the scope of the technical review. In addition, the

staff finds the program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the fuel oil system

components that are not addressed by the GALL Report and those specific component types

within the scope of the technical review, so that the intended functions can 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

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U
3.3.2.3.8 Service Water System

Summary of Technical Information in the Abplication

In Section 3.3.2.1.8 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management.'The applicdni identified the following programs that manage the

aging effects requiring management for the service water system components:

* Buried Piping Inspection Program (Appendix B.1.4)

* - System Walkdown Program (Appendix'B.1.28)

* Periodic'Surveillance and Preventive&Maintenance Program (Appendix B.1.18)

* Service Water Integrity Program (Appendix B.1.24)

In Table 3.3.2-8 of the LRA, the applicant summarized the AMRs for the service water system

components and identified which AMRs it considered to be consistent with the GALL Report.--

Staff Evaluation

The staff reviewed Table 3.3.2-8 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the service water system component groups.

The staff reviewed the AMR of the service water system componentlmateriaVenvironment'

AERM combinations that are not addressed in the GALL report and specific combinations

addressed in the GALL report within the scope of the technical review. Component AERM

combinations not addressed in the GALL report use note F through J in LRA Table 3.3.2-8.

Material and environment combinations addressed in GALL without a comparable component

use note'301. The staff determined that the applicant has identified all applicable'AERMs and

has credited appropriate AMPs for managing the AERMs. The staff also reviewed the

applicable UFSAR supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.' -

Aging Effects '

Table 2.3.3-8 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bolting, expansion joint, filter housing, flow straightener, orifice, piping, thermowell,

tubing, and valves. '' '

For these component types, the applicant identifies the following materials, environments; and .. .. . -. .. -. I., ,I .

AERMs: -

* Stainless steel components exposed to a -corndensation environment experience loss of

material.

* In a fresh' raw water environment, stainless steel components are subject to the aging

effect of cracking. ;

* Carbon steel and stainless steel bolting in a fresh raw water environment or

condensation are subject to loss of material.

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The staff reviewed the information in Section 2.3.3.8, Table 2.3.3-8, Section 3.3.2.1.8, and

Table 3.3.2-8 in the LRA. During its review, the staff determined that it needed additional

information.

The RAls are organized in two groups, general RAIs and system-specific RAls. There are no

general RAls applicable to this system.

By letter dated May 5, 2004, the staff asked the applicant for additional information on the

issues described in the system-specific RAI 3.3.2.4.8-1 and RAI 3.3.2.4.8-2. By letter dated

June 21, 2004, the applicant responded to the RAls. The following section describes RAI

3.3.2.4.8-1 and RAI 3.3.2.4.8-2, the applicant's responses to these RAls, and the staff's

evaluation of the responses.

RAI 3.3.2.4.8-1

The LRA does not identify biofouling as an aging effect/mechanism in the service water system.

The GALL Report identifies biofouling as an aging effect/mechanism for service water systems.

The staff asked the applicant to clarify what aging effect due to biofouling and/or silting is

applicable to service water components. If this applicable aging effect is not loss of material,

the applicant should clarify which specific AMP is applicable to manage biofouling in service

water components.

In its response, by letter dated June 21, 2004, the applicant stated that biofouling and silting

can create conditions that are conducive to the aging mechanisms of pitting, crevice corrosion,

and microbiologically influenced corrosion. The applicant concluded that loss of material is the

applicable aging effect resulting from the mechanisms of pitting, crevice corrosion, and

microbiologically influenced corrosion for the service water system.

The staff reviewed the applicant's response and found it to be acceptable and adequate

because the applicant clarified that biofouling and silting can create conditions that are

conducive to the aging mechanisms of pitting, crevice corrosion, and microbiologically

influenced corrosion, and that loss of material is the applicable aging effect.

RAI 3.3.2.4.8-2

Table 3.3.2-8 of the LRA identifies loss of material as an aging effect requiring aging

management for the stainless steel expansion joints, but cracking is not addressed. Industry

documents such as EPRI Report 1008035, "Expansion Joint Maintenance Guide," Revision 1,

dated May 2003, indicate that stainless steel expansion joints are susceptible to cracking when

exposed to contaminants. The staff asked the applicant to identify if cracking is considered an

aging effect for these expansion joints and to explain how the credited AMPs effectively

manage cracking, if applicable.

In its response, by letter dated June 21, 2004, the applicant stated that stainless steel is

susceptible to cracking when exposed to contaminants and temperatures above 60 0C (140 OF).

The applicant clarified that the service water system stainless steel expansion joints subject to

AMR are located in the service water pump discharge lines, and these expansion joints are

exposed to temperatures well below the 60 0

C (140 0F) threshold for cracking. The applicant

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also stated that these expansion joints are constructed of nickel-based alloy which is more

resistant to SCC than 300-series stainless steels. The applicant concluded that cracking is not

an aging effect requiring management for the stainless steel expansion joints in the service

water system. '

The staff reviewed the applicant's response and found it to be acceptable and adequate

because the applicant clarified that the service water system stainless steel expansion joints.

subject to AMR are exposed to temperatures well below the 60 0C (140 IF) threshold for !

cracking, and that these expansion joints are constructed of nickel-based alloy which is more

resistant to SCC than 300-series stainless steels.

On the basis of its review of the information provided in the LRA and the additional informationincluded in the applicant's response to the above RAls, the staff finds that the aging effects of

the service water system component types that are not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

above components in the service water system. i. _1 ,,r *S ; -- ,. . .

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified,

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program. -

Table 3.3.2-8 of the LRA identifies the following AMPs for managing the aging effects described

above for the service water system: -

* System Walkdown Program (Appendix B.1.28)

* Service Water Integrity Program (Appendix B.1.24)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Bolting and Torquing Activities Program (Appendix B.1.2)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.9, 3.0.3.2.7, 3.0.3.3.7,

and 3.0.3.3.2 of this SER, respectively.

During the audit, the staff asked the applicant to justify, for service water system component

types in LRA Table 3.3.2-8 that are consistent with the GALL Report (LRA-Note A), that the

AMP applied to carbon steel remains applicable to cast iron in a similar environment.,

By letter dated March 24, 2004, the applicant stated that where selective leaching is possible, it

credits an additional program unless the one specified program will manage selective leaching

(such as the Diesel Fuel Monitoring and Oil Analysis Programs). Selective leaching does not.

normally occur in air, lube oil, or fuel oil because the environment is not aqueous. In its

response, the applicant further stated that if cast iron components are gray-cast iron and are

exposed to an environment conducive to selective leaching, then they are managed by the .

Periodic Surveillance and Preventive Maintenance Program, Service Water Integrity Program,

or Fire Protection Program that includes the management of loss of material due to selective

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leaching. Because these programs manage the aging effects of selective leaching for gray cast

iron components, the staff finds this approach acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAts, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the service water system

component types that are not addressed by the GALL Report. In addition, the staff finds the

program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the service water

system components that are not addressed by the GALL Report and those specific component

types within the scope of the technical review, so that the intended functions can 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.9 Auxiliary Building Ventilation System

Summary of Technical Information in the Application

In Section 3.3.2.1.9 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the auxiliary building ventilation system components:

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Service Water Integrity Program (Appendix B.1.24)

In Table 3.3.2-9 of the LRA, the applicant summarized the AMRs for the auxiliary building

ventilation system components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation

The staff reviewed Table 3.3.2-9 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the auxiliary building ventilation system component groups.

The staff reviewed the AMR of the auxiliary building ventilation system component/

materiaVenvironment/AERM combinations that are not addressed in the GALL Report.

Component AERM combinations not addressed in the GALL Report use Notes F through J in

LRA Table 3.3.2-9. The staff determined that the applicant had identified all applicable AERMs

and had credited appropriate AMPs for managing the AERMs. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions are

adequate.

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I
Aging Effects -

Table 2.3.3-9 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The components that'do' not rely on the GALL Report for AMR include

heat exchanger (tubes) and tubing.

For these component types, the applicant identifies the following materials, environments, and

AERMs:

* Copper alloy components exposed to condensation are subject to the aging effects of

fouling and loss of material-wear. 'C, ., . ........... . , . ;

* In a fresh raw water environment, the same components are subject only to fouling.

* * In both air and Freon environments: copper alloy components experience no aging

effects requiring management.

The staff reviewed the information in Section 2.3.3.9, Table 2.3.3-9, Section 3.3.2.1.9, and

Table 3.3.2-9 in the LRA. There are no RAIs related to aging effects for this system.:,

On the basis of its review of the information provided in the LRA, the staff finds that the aging'

effects of the auxiliary building ventilation system component types that are not addressed by

the GALL Report are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects. Therefore, the staff

finds that the applicant has identified the appropriate aging effects for the materials and

environments associated with the above components in the auxiliary building ventilation system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that -the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-9 of the LRA identifies the following AMPs for managing the aging effects described

above for the auxiliary and radwaste area ventilation system:

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Service Water Integrity Program (Appendix B.1.24)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.7 and 3.0.3.2.7 of this

SER, respectively. :

The staff reviewed the auxiliary building ventilation system component groups exposed to an air

environment. The staff has observed that stainless: steel components exposed to air/gas,

contain'ment 'air,' indoor air (not air-conditioned),' and outdoor environments show no aging

effect. The GALL'Report does not identify an air/gas environment for these components and

materials. The staff finds that no aging effects are applicable, and thus, the absence of an

AMP for stainless steel components exposed to air is acceptable.

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On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the auxiliary

building ventilation system component types that are not addressed by the GALL Report. In

addition, the staff finds the program descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the auxiliary building

ventilation system components that are not addressed by the GALL Report and those specific

component types within the scope of the technical review, so that the intended functions can 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.10 Control Room Ventilation System

Summary of Technical Information in the Application

In Section 3.3.2.1.10 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the control ventilation system components:

* System Walkdown Program

* Periodic Surveillance and Preventive Maintenance Program

* Service Water Integrity Program

In Table 3.3.2-10 of the LRA, the applicant summarized the AMRs for the control ventilation

system components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed Table 3.3.2-10 of the LRA, which summarizes the results of AMR

evaluations in the SRP-LR for the control room ventilation system component groups.

The staff reviewed the AMR of the control room ventilation system component/materiaV

environment/AERM combinations that are not addressed in the GALL Report and specific

combinations addressed in the GALL Report that are within the scope of the technical review.

These combinations use Notes F through J in LRA Table 3.3.2-10. Material and environment

combinations addressed in the GALL Report without a comparable component use Note 301.

The staff determined that the applicant has identified all applicable AERMs and has credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions are adequate.

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I
Aging Effects '- -- e.

Table 2.3.3-10 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components that do not rely on the GALL Report for AMR

include bolting', compressor casing,-damper housing, filter housing, heat exchanger (shell), heat

exchanger (tubes), indicator housing, sight glass, sight glass housing, tubing, -and valves.

For these component types, the applicant identifies the following materials, environments, and

AERMs:

Copper alloy components exposed to condensation and lube oil environments are

subject to the aging effect of loss of material. In a fresh raw water environment, these -'

components experience'fouling.'

* Carbon steel components in a lube-oil environment are also subject to loss of material.

* Aluminum, glass, and stainless steel components in air do not experience aging effects.'

* -There is no aging effect for carbon steel components in a carbon dioxide environment.

* :In a Freon environment, both carbon'steel and copper alloy components experience no

applicable aging degradation.,

* Neither glass nor stainless steel components' in a condensation environment

experience aging effects. ;

* In an air environment, copper alloy components, in general, do not experience aging

degradation. However, copper alloy heat transfer tube components in an air

- environment are subject to fouling.

The staff reviewed the information in Sectioni 2.3.3.10, Table 2.3.3-10, Section 3.3.2.1.10, and

Table 3.3.2-10 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized in two groups, general RAls and system-specific RAls.

There are no general RAls applicable toth6 dontrol room ventilation system. -

By letter dated May 5, 2004, the staff requested the applicant to provide additional information

on the issues described in the system-specific RAI 3.3.2.4.10-1. By letter dated June 21, 2004,

the applicant responded to the RAI. The following'section describes RAI 3.3.2.4.10-1; the

applicant's responses to the RAI, and the' staff's evaluation of the responses.

RAI 3.3.2.4.10-1 -

The LRA states that all components in a carbon dioxide environment are not subject to any

aging effect. Dry carbon dioxide is not a degrading environment for carbon steel, brass, or

bronze components, but carbon steel components may be susceptible to corrosion in the

presence of moisture in the carbon dioxide environment. The'staff asked the applicant to clarify

the degree of dryness of the'carbon dioxide environment and to identify the activities in place to

establish and maintain the degree of dryness of the carbon dioxide environment necessary to

minimize aging degradation of carbon steel components during the period of extended

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operation, including the effects resulting from operations to replenish or refill the carbon dioxide.

In response, by letter dated June 21, 2004, the applicant stated that carbon dioxide is an

environment only for the control room ventilation system. The applicant clarified that carbon

steel bottles contain anhydrous (dry) carbon dioxide with a low level of impurities that minimizes

the effects of aging on components. The applicant further stated that the carbon dioxide bottles

are normally isolated from the system. The applicant concluded that, since the bottles are

pressurized, moisture cannot be introduced into them. The applicant confirmed that refilling is

done by a vendor according to vendor recommendations and that periodic monitoring of bottle

pressure detects the occurrence of leaks and identifies the need for refilling.

The staff reviewed the applicant's response and found the response to be acceptable and

adequate because the applicant indicated (1) that the carbon dioxide bottles containing

anhydrous (dry) carbon dioxide with a low level of impurities are normally isolated from the

system, and since they are pressurized, moisture cannot be introduced into the bottles, and (2)

periodic monitoring of bottle pressure detects the occurrence of leaks and identifies the need

for refilling.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects of the control room ventilation system component types that are not addressed by the

GALL Report are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects for the combinations in LRA

Table 3.3.2-10 using Notes F through J. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

above components in the control room ventilation system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-9 of the LRA identifies the following AMPs for managing the aging effects described

above for the control room ventilation system:

* System Walkdown Program (Appendix B.1.28)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

* Service Water Integrity Program (Appendix B.1.24)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.9, 3.0.3.3.7, and

3.0.3.2.7 of this SER, respectively.

The staff reviewed the control room ventilation system stainless steel components exposed to

an air environment. The staff observed that stainless steel components exposed to air/gas,

containment air, indoor air (not air-conditioned), and outdoor environments show no aging

effects. The GALL Report does not identify an air/gas environment for these components and

materials. The staff finds that no aging effects are applicable, and thus, the absence of an

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I
. 

AMP for stainless steel components exposed to air is acceptable.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the control room

ventilation system component types that are not addressed by the GALL Report. In addition, the staff finds the program descriptions in the UFSAR Supplement acceptable.'.

Conclusion%

On the basis of its review, the staff concludes that the applicant has adequately identified the;

aging effects and the AMPs credited with managing the aging effects for the control room

ventilation system components that are not addressed by the GALL Report and those specific component types within the scope of the technical review, so that the intended functions can be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). - a. ! '

- . as a , , - - r I

The staff also reviewed the applicable UFSAR Supplement program descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components; as required by 10 CFR 54.21 (d).

3.3.2.3.11 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)

Summary of Technical Information in the Application

In Section 3.3.2.1.11 of the LRA, the applicant identified the materials, environments, and aging effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for thenmiscellaneous systems in scope for

10 CFR 54.4(a)(2) components:

* Bolting and Torquing Activities Program:

* Boric Acid Corrosion Prevention Program -

Flow-Accelerated Corrosion Program: * System Walkdown Program * Water Chemistry Control Program:--;:;

In Table 3.3.2-11 of the LRA, the applicant summarized the AMRs for the miscellaneous

systems in scope for 10 CFR 54.4(a)(2) components and identified which AMRs it considered to

be consistent with the GALL Report. - i .

Staff Evaluation - -,

The staff reviewed Table 3.3.2-11 of the LRA, which summarized the results of AMR

evaluations in the SRP-LR for the miscellaneous systems in scope for 10 CFR 54.4(a)(2)

component groups.

The staff reviewed the AMR of the miscellaneous systems in scope for 10 CFR 54.4(a)(2)- component/materiaVenvironment/AERM combinations in various systems that, in general, are

not addressed in the GALL Report. Theselcombinations use Note 304 in LRA Table 3.3.2-11.

The staff determined that the applicant had identified all applicable AERMs and had credited

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appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions are adequate.

Aaing Effects

Table 2.3.3-11 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components that do not rely on the GALL Report for AMR

include bolting, filter housing, heat exchanger (shell, channel head), heat exchanger (heating or

cooling coil when not enclosed in a housing), level glass gauge, orifice, piping, pump casing,

tank, thermowell, tubing, valve, and ventilation unit housing.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* In an air environment, aluminum, carbon steel, and carbon steel (coated) components

are subject to loss of material. In the same environment, copper alloy, glass and

stainless steel components experience no aging effect.

* In both condensation and treated water environments, aluminum, carbon steel copper

alloy, and stainless steel components experience the aging effect of loss of material.

* In a hydrazine/ammonia environment, stainless steel components are subject to loss of

material and cracking. Carbon steel, copper alloy, and stainless steel components

experience loss of material, but glass components in the same environment experience

no aging effects.

* In steam or treated water greater than 104 0C (220 0F), carbon steel components are

subject to cracking-fatigue, loss of material, and erosion.

* Stainless steel components experience loss of material and cracking in sodium

hydroxide, treated borated water greater than 60 OC (140 OF), treated borated water

greater than 132 CC (270 OF), and untreated water greater than 60 OC (140 OF).

* Stainless steel components experience cracking-fatigue in treated borated water greater

than 132 0 C (270 OF).

* In an untreated water environment, carbon steel, carbon steel (coated) copper alloy, and

stainless steel components are subject to loss of material.

* Stainless steel components in an untreated borated water environment experience loss

of material.

* Carbon steel bolting exposed to air and condensation is subject to loss of material and

loss of mechanical closure integrity.

The staff reviewed the information in Section 2.3.3.11, Table 2.3.3-11, Section 3.3.2.1.11, and

Table 3.3.2-11 in the LRA. During its review, the staff determined that it needed additional

information. The RAls were organized in two groups, general RAls and system-specific RAls.

General RAIs applicable to this system include RAls 3.3-1 and 3.3-2.

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I
By letter dated May 5, 2004, the staff asked the applicant to provide additional information on

the issues described in RAls 3.3-1 and 3.3-2. Byletter dated June 21, 2004, the applicant

responded to the RAls. Section 3.3.2.3.0,of this SER describes the general RAls, applicant's

responses, and the staff's evaluation of the, responses.,. -

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects of the above miscellaneous systems in scope for 10 CFR 54.4(a)(2) component types

that are not addressed by theGALL Report are consistent with industry experience for these.

combinations of materials and environments. ;The staff did not identify any omitted aging

effects for the combinations in LRA Table 3.3.2,11 using Notes F through J.- Therefore, the

staff finds that the applicant has identified the appropriate aging effects for the materials and,:

environments associated with the above components in the miscellaneous systems in scope for

10 CFR 54.4(a)(2).

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the UFSAR Supplement contains an adequate

description of the program.

Table 3.3.2-9 of the LRA identifies the following AMPs for managing the aging effects described

above for the miscellaneous systems in scope for 10 CFR 54.4(a)(2):-,

* ,,System Walkdown Program (Appendix B.1.28)

* ,Flow-Accelerated Corrosion Program (Appendix B.1.11)

* , Water Chemistry Control Program (Appendix B.1.30)

* ,Bolting and Torquing Activities Program (Appendix B.1.2)

* , Boric Acid Corrosion Prevention Program (Appendix B.1.3)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.9, 3.0.3.1, 3.0.3.3.11,

3.0.3.3.2, and 3.0.3.2.1 of this SERjrespectively.,

The applicant credits theWater.Chemistry Control Program with managing aging effects in the

stainless steel, carbon steel, copper alloy, and aluminum components exposed to treated

borated water or treated water. During its review, the staff determined that it needed additional

information and issued RAI 3.3-2. Section 3.3.2.3.0 of this RAI describes RAI 3.3-2, the

applicant's response to this RAI, and the staff's evaluation of the response. -

.: . . . ' - * . *; -

By letter dated May 5, 2004, the staff asked the applicant for additional information on the

issues described in the system-specific RAI 3.3.2.4.11-1. By letter dated June 21, 2004, the

applicant responded to the RAI. The following section describes RAI 3.3.2.4.11-1, the

applicant's responses to this RAI, and the staff's evaluation of the responses.

RAI 3.3.2.4.1 1-1,:-:,> ;

Table 3.3.2-11 of the LRA identifies various components exposed internally to treated water

and other environments with a pressure boundary function. The applicant credited the System

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Walkdown and Water Chemistry Control Programs with managing the loss of material and

cracking of the internal surfaces of these components. The system walkdown is a visual

inspection of external surfaces. The staff asked the applicant to clarify how a visual inspection

of external surfaces assures that internal surfaces are effectively managed when the internal

and external environments are different. If evidence of leakage is necessary to determine if an

aging effect has occurred, the staff asked the applicant to provide technical justification that a

failure of the pressure boundary is acceptable.

In its response, by letter dated June 21, 2004, the applicant cited five programs credited with

managing aging effects for equipment that meets the 10 CFR 54.4(a)(2) criteria. Although

three of the programs do not require leakage detection, the applicant explained that the System

Walkdown Program manages the effects of aging by detecting leakage through visual

inspections. The applicant addressed long-term and short-term exposure effects resulting from

the leakage which would be detected by walkdowns and other normal plant operational

activities. The applicant concluded that the operating experience and routine operator

rounds/system walkdowns, in conjunction with a Flow-Accelerated Corrosion Program, Water

Chemistry Program, Bolting and Torquing Activities Program, and Boric Acid Corrosion

Prevention Program, provide assurance that leaks from nonsafety-related SSCs will not

preclude the satisfactory accomplishment of required safety functions.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3.2.4.11-1 and does not concur that the

external visual inspections for leakage are appropriate for managing internal aging effects for

(a)(2) system components using the System Walkdown Program alone. For all components

within license renewal scope, the staff requires AMPs to prevent fluid leaks rather than only

detecting and mitigating the consequences of the leak. An NRC letter to NEI dated March 15,

2002, clarified that the applicant has two options when performing its scoping evaluation for

nonsafety-related SSCs. If the applicant cannot demonstrate that the mitigative features (e.g.,

spray and drip shields, seismic supports, flood barriers, etc.) are adequate to protect safetyrelated SSCs from the consequences of failures of nonsafety-related SCCs, then the applicant

should use the preventive option by including' the nonsafety-related SCCs within scope. Since

the ANO-2 nonsafety-related SSCs are within scope, the preventive action is applicable with

appropriate preventive rather than mitigative AMPs. Leak detection is considered a mitigative

program, and internal inspections are considered a preventive program. The staff explained

this concern to the applicant in a phone call on June 22, 2004, and the applicant agreed to

supply additional information regarding aging management of system components that rely only

on the plant walkdown program. On July 2, 2004, the applicant provided additional information

to support the aging management of (a)(2) components. This response states that, for the nine

pressurized systems containing raw or untreated water, operating experience and maintenance

inspections have not identified any abnormal corrosion in 25 years of operation.

The staff was concerned that the use of external visual inspections alone is not appropriate to

manage internal aging effects. By letter dated September 10, 2004, the applicant stated that

ANO-2 will implement a one-time inspection program for the components subject to aging

management review that were included for 1 OCFR54.4(a)(2) in the following systems:

* Auxiliary building heating and ventilation

* Auxiliary building sump

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I
Drain collection header - Liquid radwaste management : ;

* Post accident sampling

*- Resin Transfer

* Regenerative waste

* Spent Resin

The applicant response further stated that the one-time inspection program will be consistent

with NUREG-1801 Vol.2, Xl.M32, one-time inspection and a new SAR Section A.2.1.34 was

included.

The staff was concerned that one-time inspections may not be appropriate for systems

containing raw or untreated water unless there is sufficient data to conclude that degradation is

not occurring or is occurring very slowly .-The staff was also concerned that the one-time

inspection program does not apply to the floor drains in the turbine building sump system.

GALL AMP XL.M32 states that one-time inspections or any other action or program are to be

reviewed by the staff on a plant-specific basis., The'applicant was requested to submit for

review their Appendix B program for one-time inspections. The applicant was requested to

justify that one-time inspections are appropriate'rather than periodic inspections. For example,

the applicant was requested to clarify that, for these systems, there is sufficient data to

conclude that degradation is not expected to occur or is expected to progress very slowly and

that follow-up examinations would be performed to monitor the progression of any aging

degradation. The applicant was also requested to justify why one-time inspections are not

required for the in scope floor drains in the turbine building sump system.

By letter dated September 23, 2004, the applicant clarified that the one-time inspection will be

performed near the end of the current operating term and aging of these components, if any,

should progress slowly. The applicant indicated that, if loss of material due to corrosion is

found, an evaluation will be performed to determine the rate of corrosion and appropriate

corrective action taken. The applicant also stated that the turbine building sump system will be

included with the eight systems managed by the one-time inspection program.

This response is adequate and acceptable to resolve the staff's concern regarding one-time

inspections for 1 OCFR54.4(a)(2) components because the applicant has identified that the

aging effects should progress very slowly in these components and the turbine building sump

system will also be managed by the one-time inspection program. All issues related to RAI

3.3.2.4.11-1 are resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAls, the staff finds the applicant has

identified appropriate AMPs for managing the aging effects of the miscellaneous systems in

scope for 1OCFR54.4(a)(2) component types that are not addressed by the GALL report. In

addition, the staff finds the program descriptions in the UFSAR supplement acceptable.

3.3.2.4.12 Miscellaneous Components

During the site inspection that was conducted by the staff on November 15 through 19, 2004, a

walk-down of various systems was conducted. The staff noted that several component types

that were brought into the scope of license renewal as a result of RAI 2.1-4 were included in the

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scope of license renewal. The applicant stated that the material and environment combinations

of these components had been previously reviewed by the NRC staff. In a letter dated

February 28, the applicant submitted the a table describing the additional components. The

staff reviewed the table and determined that the aging effects could be adequately managed by

the AMP's credited for the components. The inspection item associated with this issue is

closed.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and the AMPs credited with managing the aging effects for the miscellaneous

system components that are not addressed by the GALL Report and those specific component

types within the scope of the technical review, 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 descriptions and concludes

that the UFSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.3 Conclusion

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the aging effects associated with the auxiliary systems components will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

auxiliary systems, as required by 10 CFR 54.21(d).

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3.4 Steam and Power Conversion Systems -

This section of the SER documents the staff's review of the applicant's AMR results for the

steam and power conversion system components and component groups associated with the

following systems:

* main steam system

* main feedwater system

* emergency feedwater system

3.4.1 Summary of Technical Information In the Application

In Section 3.4 of the LRA, the applicant provided the results of the AMRs of the main steam,

main feedwater, and emergency feedwater. system components and component types listed in

Tables 2.3.4-1 through 2.3.4-3 of the LRA. The applicant also listed the materials,

environments, aging effects requiring management, and AMPs associated with each system.

In Table 3.4.1, "Summary of the Aging Management Programs for the Steam and Power

Conversion System Evaluated in Chapter VIII of NUREG-1801," of the LRA, the applicant

'provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for

the main steam, main feedwater, and emergency feedwater system components'and

component types. In Section 3.4.2.2 of the LRA, the applicant provided information concerning

Table 3.4.1 components for which the' GALL Report recommends further evaluation.

3.4.2 Staff Evaluation'

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information'

to demonstrate that the effects of aging for the steam and power conversion system

components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). -- -

The staff performed an audit and review 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 determine that the material presented in'

the LRA was applicable and that the applicant had 'identified the appropriate GALL AMPs.'

'Section 3.0.3 of this SER documents the staff's evaluations of the AMPs. The staff's audit and

review findings are documented in the audit report issued on August 19, 2004 and summarized

in Section 3.4.2.1 of this SER.

The staff also performed an audit of those AMRs that were consistent with the GALL Report

and for which further evaluation is recommended. During' the audit, the staff determined that

the applicant's further evaluations were consistent with the acceptance-criteria in Section'

3.4.2.2 of the SRP-LR. The staff's audit findings are documented in the audit report and

summarized in Section 3.4.2.2 of-this SER. ---..--

The staff conducted a'technical review of the remaining AMRs'that were not consistent with the'

GALL Report. 'The' review included evaluating whether the applicant had identified all plausible

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aging effects and whether the aging effects listed were appropriate for the combination of

materials and environments specified. Section 3.4.2.3 of this SER documents the staff's review

findings.

Finally, the staff reviewed the AMP summary descriptions in the FSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

reactor system components.

Table 3.4-1 below summarizes 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

ComponentGroup ; AiEff ;ai

, Mecghan - ' . *; R oA -- - ;, -- tlfflvaIu .i;*"-

Piping and fittings in Cumulative fatigue TLAA in accordance TLAA-Metal Consistent with

main feedwater line, damage with Fatigue GALL, which

steam line, and 10 CFR 54.21(c)) recommends

auxiliary feedwater further evaluation

(AFW) piping (PWR

only)

(Item 3.4.1-1) . . .

Piping and fittings, Loss of material Water Chemistry Water Chemistry Consistent with

valve bodies and due to general and One-Time Control (B.1.30), GALL, which

bonnets, pump (carbon steel only), Inspection Periodic recommends

casings, tanks, pitting, and crevice Surveillance and further evaluation

tubes, tubesheets, corrosion Preventive

channel head, and Maintenance

shell (except main (B.1.18)

steam system)

(Item 3.4.1-2)

AFW piping Loss of material Plant specific Water Chemistry Consistent with

(Item 3.4.1-3) due to general, Control (B.1.30), GALL, which

pitting, and crevice PSPM (B.1.18), recommends

corrosion, MIC, and Service Water further evaluation

biofouling Integrity (B.1.24)

Oil coolers in AFW Loss of material Plant specific Oil Analysis Consistent with

system (lubricating due to general (B.1.17) GALL, which

oil side possibly (carbon steel only), recommends

contaminated with pitting, and crevice further evaluation

water) corrosion, and MIC

(Item 3.4.1-4) .

External surface of Loss of material. Plant specific System Walkdown Consistent with

carbon steel due to general (B.1.28) GALL, which

components corrosion recommends

(Item 3.4.1-5) further evaluation

Carbon steel piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with

and valve bodies flow-accelerated Corrosion Corrosion (6.1.11) GALL, which

(Item 3.4.1-6) corrosion recommends no

further evaluation

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I
ComponentGroup:.:: Mechanim Pirf GALL- CAMP .n A 7.. _'Sta -'

.,,. *. Aging , .fecI . ... ,vl~in

Carbon steel piping Loss of material Water Chemistry Water Chemistry Consistent with

and valve bodies in due to pitting and Control (b.1.30) GALL, which

main steam system crevice corrosion recommends no'

(Item 3.4.1-7) - . - further evaluation

Closure bolting in Loss of material Bolting Integrity System Walkdown Consistent with

high-pressure or due to general (B.1.28), Bolting GALL, which

high-temperature corrosion; crack and Torquing recommends no

systems Initiation and growth Activities (B.1.2) further evaluation

(Item 3.4.1-8) due to cyclic , .

loading and/or SCC ,_a__.,

Heat exchangers Loss of material 'Opern-Cycl6 Cooling Not Applicable to Consistent with

and coolers/ due to general Water System ANO-2 GALL, which

condensers (carbon steel only), recommends no

serviced by open- pitting, and crevice further evaluation

cycle cooling water corrosion, MIC, and

(Item 3.4.1-9) biofouling; buildup

of deposits due to

biofouling -

Heat exchangers Loss of material Closed-Cycle Not Applicable to Consistent with

and coolers/ due to general Cooling Water ANO-2 GALL, which

condensers (carbon steel only), System recommends no

serviced by closed- pitting, and crevice,.. - further evaluation

cycle cooling water corrosion ;

(Item 3.4.1 -1 0) ,,

External surface of Loss of material Aboveground Not Applicable to Consistent with

aboveground due to general Carbon Steel Tanks ANO-2 GALL, which

condensate storage' (carbon steel only), , recommends no

tank pitting, and crevice --- - further evaluation

(Item 3.4.1-11). . corrosion . * ' . ..

External surface of Loss of material Buried Piping and Not Applicable to Consistent with

buried condensate due to general, Tanks Surveillance ANO-2 GALL, which

storage tank and pitting, and crevice recommends no

AFW piping corrosion, MIC or further evaluation

(Item 3.4.1-12) ,

Buried Piping and

Tanks Inspection , Consistent with

- GALL, which

recommends further

evaluation.

External surface of Loss of material Boric Acid Not Applicable to Consistent'with

carbon steel due to boric acid Corrosionr.: ANO-2 GALL, which

components corrosion Prevention - recommends no

(Item 3.4.1-13) . further evaluation

The staff's review of the ANO-2 steam and power conversion system and associated

components followed one of several approaches. One approach, documented in Section

3.4.2.1, involves the staff's audit and review of the AMR results for components in the steam

and power conversion system that the applicant indicated are consistent with the GALL Report

and do not require further evaluation. Another approach, documented in Section 3.4.2.2,

involves the staff's audit and review of the AMR results for components in the steam and power

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conversion system that the applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A third approach, documented in Section 3.4.2.3,

involves the staff's technical review of the AMR results for components in the steam and power

conversion system that the applicant indicated are not consistent with the GALL Report or are

not addressed in the GALL Report. Section 3.0.3 of this SER documents the staff's review of

AMPs that are credited with managing or monitoring the aging effects of the steam and power

conversion system components.

3.4.2.1 AMR Results That Are Consistent with the GALL Report

In Sections 3.4.2.1.1 through 3.4.2.1.3 of the LRA, the applicant identified the materials,

environments, and aging effects requiring management. The applicant identified the following

programs that manage the aging effects related to the power and conversion system

components:

* Bolting and Torquing Activities Program

* Flow-Accelerated Corrosion Program

* System Walkdown Program

* Water Chemistry Control Program

* Oil Analysis Program

* Periodic Surveillance and Preventive Maintenance Program

In Tables 3.4.2-1 through 3.4.2-3 of the LRA, the applicant summarized the AMRs for the steam

and power conversion systems and identified which AMRs it considered to be consistent with

the GALL Report.

The staff conducted an audit of the information provided in the LRA and program bases

documents, which are available at the applicant's engineering office. On the basis of its audit,

the staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are consistent with the AMRs in the GALL Report. Therefore, the staff finds that the

applicable aging effects were identified and are appropriate for the combination of materials

and environments listed.

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 indicated 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 determine 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 determine

consistency with the GALL Report. The staff determined that it had reviewed and accepted the

identified exceptions to the GALL Report. 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

is valid for the site-specific conditions.

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Note C indicates that the component for the AMR line item is different, but 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 could not

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 under review. The staff audited these line items to

determine consistency with the GALL Report: The staff also determined whether the AMR line

item of the different component applies to the component under review and whether the AMR is

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item is different, but 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

determine, consistency with the GALL Report.' The staff determined that the AMR line item of

the different component applies to the component under review. The staff determined that it

had reviewed and accepted the identified exceptions to the GALL AMPs. 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 is 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 determine consistency with the GALL Report. The staff also' determined whether the

identified AMP would manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA and program

bases documents, which are available at the applicant's engineering office. On the basis of its

audit and review, the staff confirms that the AMR results, which the applicant claimed to be

consistent with the GALL Report, are consistent with the AMRs in the GALL Report. Therefore,

the staff finds that the applicant identified the applicable aging effects, and they are appropriate

for the combination of materials and environments'listed.

On the basis of its audit,'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).

Conclusion -

The staff has'determined the applicant's'claim of consistency with the GALL Report. The staff

reviewed information pertaining to the applicant's consideration of recent operating experience,

and proposals for managing associated aging effects. On the basis of its review, the staff finds

that the applicant has demonstrated that the effects of aging for these components will be

adequately managed so that their intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

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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 Section 3.4.2.2 of the LRA, the applicant provides further evaluation of aging management

as recommended by the GALL Report for steam and power conversion systems. 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, and crevice corrosion, microbiologically

influenced corrosion, and biofouling

* general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion

* quality assurance for aging management for nonsafety-related components

Staff Evaluation

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 reviewed the applicant's evaluation to determine whether it adequately

addressed the issues in its additional evaluation. The staff also audited the applicant's further

evaluations against the criteria contained in Section 3.4.2.2 of the SRP-LR. The audit report

issued August 19, 2004, documents the details of the staff's audit.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

3.4.2.2.1 Cumulative Fatigue Damage

As stated in the SRP-LR, fatigue is a TLAA as defined in 10 CFR 54.3. In accordance with

10 CFR 54.21(c)(1), TLAAs must be evaluated in accordance with 10 CFR 54.21(c)(1). Section

4.3 of this SER documents the staff's review of the applicant's evaluation of this TLAA. In

performing this review, the staff followed the guidance in Section 4.3 of the SRP-LR.

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I
3.4.2.2.2 Loss of Material due to General,) Pitting; and Crevice Corrosion

In Section 3.4.2.2.2 of the LRA, the applicant addressed the GALL Report recommendation for

further evaluation to evaluate the effectivenes's'of the Water Chemistry Control Program in

managing loss of material due to general, pitting, and crevice corrosion. -. l --

Section 3.4.2.2.2 of the SRP-LR states that the management of loss of material due to general,

pitting,'and crevice corrosion should be evaluated further for carbon steel piping and fittings, -

valve bodies and bonnets,' pump casings, pump suction and discharge lines, tanks, tubesheets,

channel heads, and shells except for main'stearm system components. It also recommends

further evaluation of loss of material due to pitting and crevice corrosion for stainless steel tanks

and heat'exchanger/cooler tubes. The Water Chemistry Program relies on monitoring and

control of water chemistry based on the EPRI guidelines of TR-102134 for secondary water

chemistry to manage the effects of loss of material due to general, pitting, or crevice corrosion.

However, corrosion may occur at locations of stagnant flow conditions. Therefore, the

effectiveness of the Chemistry Control Program should be evaluated 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 determine the effectiveness of the

Water Chemistry Program. 'A one-time inspection'of selected components and susceptible

locations is an acceptable method to ensure that corrosion is not occurring and that the

components' intended function will be maintained during the period of extended operation.

For the components for which this evaluation' is required, the applicant credited the Primary and

Secondary Water Chemistry Control Program (AMP B.1.30.3) with managing loss of material.

The Water Chemistry Control Program minimizes loss of material and provides for the

inspection of systems when they are opened for maintenance, which addresses the verification'

program recommendation in the GALL Report. The applicant credited the Periodic Surveillance

and Preventive Maintenance Program (AMP B.1.18) with supplementing the Water Chemistry

Control Program for portions of the emergency feedwater system. The Water Chemistry - -

Control Program provides for the inspection of systems when they are opened for maintenance,

which addresses the one-time inspection recommendation in the GALL Report. -The applicant's

existing Primary and Secondary Water Chemistry Control Program relies on the EPRI

guidelines of TR-1 02134 for secondary water' chemistry to manage 'the effects of loss of

material due to general, pitting, or crevice corrosion. The applicant does'not have a one-time

inspection program of selected components and susceptible locations, which is suggested in

the GALL AMP XI.M32 as a means to determine the program's effectiveness.. Rather, the

applicant credited on-going routine maintenance and inspection activities with'determining the'

effectiveness of the Primary and Secondary Water Chemistry'Control Program.

The staff reviewed the effectiveness of the Primary 'and Secondary Water Chemistry Control -

Program by examining routine component inspections that are performed by chemistry,

maintenance, and engineering staff when primary'and secondary systems were opened for'

maintenance, when an adverse chemistry trend existed, or when requested by the chemistry or

engineering departments. The components inspected have included areas that are susceptible

to the aging effects identified in the LRA. The inspections performed include inspections in

systems such as emergency feedwater and EDGs which are normally in standby, condensate

storage tanks, feedwater heaters, moisture separator reheaters, chillers, main steam safety

valves, and blowdown heat exchangers. All of these components have areas that are

susceptible to the aging effects addressed in Section 3.4.2.2.2 of the LRA.

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Seeking additional confirmation of the effectiveness of the Water Chemistry Programs, the staff

reviewed operating experience documented in the applicant's engineering report, which

included an audit of condition reports (CRs), CR trending data, and interviews with the

applicant's technical staff regarding the Water Chemistry Program's operating experience. The

operating experience review did not identify component failures or significant adverse

conditions such as aging effects in the systems that were the result of an ineffective Water

Chemistry Program. Also, the CR trending data did not identify recurrent component

degradation occurring in the steam and power conversion systems. The audit of CRs, CR

trending data, and personnel interviews provided additional confirmation of the effectiveness of

the Primary and Secondary Water Chemistry Control Program.

The staff finds that the applicant has demonstrated that the effects of aging for loss of material

will be adequately managed so that the intended functions will be maintained consistent with

the CLB during the period of extended operation.

3.4.2.2.3 Loss of Material due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion, and Biofouling

In Section 3.4.2.2.3 of the LRA, the applicant addressed loss of material in carbon steel piping

and fittings for untreated water from the backup water supply in the emergency feedwater

system.

Section 3.4.2.2.3 of the SRP-LR states that loss of material due to general corrosion, pitting,

and crevice corrosion, MIC, and biofouling could occur in carbon steel piping and fittings for

untreated water from the backup water supply in the auxiliary feedwater system. The GALL

Report recommends further evaluation to ensure that these aging effects are adequately

managed.

The applicant stated that it addressed the portion of the lines from the service water system to

the emergency feedwater system that are exposed to untreated water as part of the service

water system (LRA Item 3.3.1-17 of Table 3.3.1). With exceptions, the Service Water Integrity

Program (AMP B.1.24) is the equivalent of the Open-Cycle Cooling System Program described

in the GALL AMP XL.M20, "Open-Cycle Cooling Water System." Section 3.0.3.2.7 of this SER

evaluates the Service Water Integrity Program.

The Service Water Integrity Program is supplemented by the Primary and Secondary Water

Chemistry Control Program (AMP B.1.30.3) and the Periodic Surveillance and Preventive

Maintenance Program (AMP B.1.18) which manage loss of material and fouling. Although

biofouling is not, in itself, an aging effect, these programs manage the effects that may result

from biofouling in carbon steel piping and fittings for untreated water from the backup water

supply in the emergency feedwater system. The staff reviewed the Primary and Secondary:,

Water Chemistry Control Program and the PSPM Program. Sections 3.0.3.1 and 3.0.3.3.7 of

this SER, respectively, document the staff's evaluation of these programs. The staff finds that

the PSPM Program effectively manages the aging effects of loss of material.

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3.4.2.2.4 General Corrosion L

In Section 3.4.2.2.4 of the LRA; the applicant stated that loss of material due to general

corrosion could occur on external surfaces of carbon steel SCs, including closure bolting. The

applicant credited the System Walkdown Program (AMP B.1.28) with managing loss of material

for the external surfaces of carbon steel SCs, including bolting indoors and outdoors.

Section 3.4.2.2.4 of the SRP-LR states that loss of material due to general corrosion could

occur on the external surfaces of all carbon steel SCs, including' closure boltings, exposed to

operating temperatures less than 212 "F. The GALL Report recommends further evaluation to

ensure adequate management of this aging effect.;

The staff reviewed the applicant's proposed program to ensure that an adequate program will

be in place for the management of this aging effect. Based on its review of the System

Walkdown Program, the staff concludes that the program will adequately manage'these agingeffects. Section 3.0.3.3.9 of this SER documents the staff's evaluation of this program.

3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion . '

In Section 3.4.2.2.5 of the LRA, the applicant addressed (1) loss of material due to general

corrosion (carbon steel only), pitting and crevice corrosion, and microbiologically influenced

corrosion in stainless steel and carbon'steel components exposed to lubricating oil in the

emergency feedwater system and (2) loss of material in underground piping and fittings and

storage tanks for steam and power conversion systems.

Section 3.4.2.2.5 of the SRP-LR addresses loss of material due to general corrosion (carbon

steel only), pitting and crevice corrosion, and MIC which could occur in stainless steel and

carbon steel shells, tubes, and tubesheets within the bearing oil coolers (for steam turbine

pumps) in the auxiliary feedwater system. The GALL Report recommends further evaluation to

ensure adequate management of these aging effects.

Section 3.4.2.2.5 of the SRP-LR also addresses loss of material due to general corrosion,

pitting and crevice corrosion, and MIC, which could occur in underground piping and fittings and

the emergency condensate storage tank in the auxiliary feedwater system and the underground

condensate storage tank in the condensate system. 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 due to general corrosion, pitting and crevice corrosion,

and MIC. The effectiveness of the Buried Piping and Tanks Inspection Program should be

reviewed to evaluate an applicant's inspection frequency and operating experience with buried

components, thus'ensuring that loss of material is not occurring.

The applicant stated that the Oil Analysis Program (AMP B.1.17) manages the loss of material

aging effect for stainless steel and carbon steel components exposed to lubricating oil in the'

emergency feedwater system. The staff review found that the Oil Analysis Program adequately

manages the effects of aging of loss of material for stainless and carbon steel components

exposed to lubricating oil. Section 3.0.3.3.6 of this SER documents the staff's evaluation of this

AMP.

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3.4.2.2.6 Quality Assurance for Aging Management for Nonsafety-Related Components

Section 3.0.4 of this SER provides the staff's evaluation of the applicant's Quality Assurance

Program.

Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations,

conducted in accordance with the GALL Report, are consistent with the acceptance criteria in

Section 3.4.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3 AMR Results That Are Not Consistent with the GALL Report

Summary of Technical Information in the Application

In Tables 3.4.2-1 through 3.4.2-3 of the LRA, the applicant gave additional details of the results

of the AMRs for material, environment, aging effects requiring management, and AMP

combinations that are not evaluated in the GALL Report.

In Tables 3.4.2-1 through 3.4.2-3, the applicant indicated, via Notes F through J, that neither

the identified component nor the material and environment combination is evaluated in the

GALL Report and provided information concerning how the aging effect will be managed.

Note F indicates that the material is not in the GALL Report for the identified component.

Note G indicates that the environment is not in the GALL Report for the identified component

and material.

Note H indicates that the aging effect is not in the GALL Report for component, material, and

environment combination.

Note I indicates that the aging effect in the GALL Report for the identified component, material,

and environment combination is not applicable.

Note J indicates that neither the identified component nor the material and environment

combination is evaluated in the GALL Report.

For component type, material, and environment combination that are not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant

demonstrated that it will adequately manage the effects of aging so that the intended function

will be maintained consistent with the CLB during the period of extended operation.

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The staff evaluation is discussed below. '' ''- - '

3.4.2.3.1 Main Steam System

Summary of Technical Information in the A&dlication

In Section 3.4.2.1.1 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the main steam system components:

* Bolting and Torquing Activities

* Flow-Accelerated Corrosion

* System Walkdown

* Water Chemistry Control

In Table 3.4.2-1 of the LRA, the applicant summarized the AMRs for the main steam system

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed Table 3.4.2-1 of the LRA; which summarized the results of AMR evaluations

in the SRP-LR for the main steam system component groups. The staff reviewed the AMR of'

the main steam system componentmateriaVenvironmentlAERM combinations that are not

addressed in the GALL Report. These combination's use Notes F through J in LRA Table

3.'4.2-1, except for those that had past precedents. The staff also reviewed those.combinations

in Table 3.4.2-1, with Notes A through E, which had associated emerging issues. The staff

confirmed that the applicant had identified all applicable AERMs and had credited appropriate

AMPs for'managing the AERMs. The staff also reviewed the applicable UFSAR Supplements

for the AMPs to ensure that the program decriptions were adequate.

The applicant identified no aging effects for stainless steel components exposed to air,

including expansion joint, piping, thermrowell, tubing, and valve component types. The GALL

-'Report does not'identify air as an environmerit'for these components and materials.

On the basis of current industry research arid operating experience, dry air on metal will not

result in aging that will be of concern'durin'g the period of extended operation. The external

environments referred to are typical of ambient air (e.g., under a shelter, indoors, or in an

air-conditioned enclosure or room). Therefore; the staff concludes that there are' no aging

effects requiring management for stainless steels in an air environment.

Aging Effects

Table 2.3.4-1 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bolting, expansion joint, orifice, pipiring steam trap, thermowell, tubing, and valve.

For these component types, the applicant identified the following materials, environments, and

AERMS:

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* Carbon steel bolting in air (external) environments is subject to loss of material and loss

of mechanical closure integrity.

* Carbon steel components in air (external), steam greater than 220 0F (internal), and

treated water greater than 220 OF (internal) environments are subject to loss of material.

* Stainless steel bolting in air (external) environments is subject to loss of mechanical

closure integrity.

* Stainless steel components in steam greater than 270 OF (internal) and treated water

greater than 270 OF (internal) environments are subject to loss of material and cracking.

* Stainless steel components in air (external) environments experience no aging effects.

During its review, the staff determined that it needed additional information.

In LRA Table 3.4.1, Item 3.4.1-8, under "Discussion," the applicant stated that for closure

bolting, the aging effect requiring management is loss of mechanical closure integrity, which

includes a broader range of aging mechanisms than those included in this line item (i.e., loss of

material due to general corrosion and crack initiation and growth due to cyclic loading and/or

SCC). The applicant also stated that it uses the System Walkdown Program to supplement the

Bolting and Torquing Activities Program to maintain bolting integrity. In RAI 3.2-1(1), (2), and

(3), the staff asked the applicant to (1) explain the extent to which AMR Item 3.4.1-8 deviates

from the ANO-2 AMR results; (2) clarify whether the aging effect of "loss of mechanical closure

integrity" indeed includes loss of material and cracking, and, specifically, what other aging

effects/mechanisms are included in the "broader range"; and (3) discuss how it will manage

each of the identified aging effects and why the approach to managing the aging effects is

adequate.

By letter dated April 6, 2004, the applicant stated that it does not consider LRA Table 3.4-1,

Item 3.4.1-8, to match the ANO-2 AMR results because the aging effects and programs used to

manage them do not match. The applicant stated that the differences in the ANO-2 aging

effects are that loss of mechanical closure integrity is considered an aging effect requiring

management for high-temperature bolting, and cracking is not considered an aging effect

requiring management. At ANO-2, the potential for SCC of bolting in non-Class 1 systems is

minimized by using lower yield strength carbon steel bolting material and limiting contaminants

such as chlorides and sulfur in lubricants and sealant compounds. Consistent with the GALL

Report, the ANO-2 AMR identifies loss of material as an aging effect requiring management.

However, for carbon steel bolting in the steam and power conversion systems, the System

Walkdown Program manages loss of material.

The staff found that the applicant's response adequately explains the differences between AMR

Item 3.4.1-8 and the ANO-2 AMR results for the closure bolting in the steam and power

conversion systems, including how the aging effect of loss of material will be managed. RAI

3.4-1(1 ) is therefore closed.

The applicant stated that the words "broad range" refer to the fact that loss of mechanical

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closure integrity is identified as an aging effect requiring management for bolting in two cases.

First, bolting in high-temperature systems, and in applications subject to significant vibration, is

subject to loss of mechanical closure integrity resulting from loss of pre-load, which is managed

by the Bolting and Torquing Activities Program. The same bolted closures may be subject to

loss of material, if they are carbon steel or wetted stainless steel. If so, another program, such

as the System Walkdown Program,'would manage the loss of material. Second, in a case

where the carbon steel bolting is exposed to borated water leakage, loss of material may

progress to such an extent that it will affect the mechanical closure integrity. Thus, the

applicant conservatively considered both loss of material and loss of mechanical closure

integrity to be aging effects requiring management.' In general, however, loss of mechanical

closure integrity does not cover the aging effects of loss of material or cracking. Based on this

information, the staff determined that the applicant has adequately delineated the aging effects

included under the "loss of mechanical closure integrity" and has identified the associated

AMPs to manage these aging effects. RAls 3.2-1(2) and (3) are therefore closed.

In LRA Table 3.4.2-1 ,the applicant stated that for the main steam system, a Water Chemistry

Control Program manages cracking and loss of material for stainless steel components in

steam greater than 270 0F (internal) and treated water greater than 270 0F (internal) -

environments. In RAI 3.4-3, the staff requested that the applicant explain why a supplemental

inspection is not needed to determine the effectiveness of the Water Chemistry Control

Program. By letter dated April 6, 2004, the applicant stated that for the steam and power

conversion systems' stainless steel components, the GALL Report identifies only the

condensate storage tank and heat exchanger tubes as requiring augmentation of the Water

Chemistry Program.' Other stainless steel components require no confirmation. However, the

applicant provided the following information to confirm the effectiveness of the Water Chemistry

Programs at ANO-2:

The effectiveness of the Water Chemistry programs at ANO-2 has been

confirmed through routine component inspections that are performed by!

chemistry, maintenance and engineering personnel. This includes the primary

and secondary water chemistry programs. These inspections were performed

when systems were opened for maintenance, when an adverse chemistry trend,

existed, or when requested by the chemistry or engineering departments. The

areas inspected have included stagnant areas that are most susceptible to aging

effects identified in the LRA. In addition,for many components covered by the

Primary and Secondary Water Chemistry Control Program, such as those in the

reactor coolant system and steam generators, inspection activities included in

other aging management programs provide additional confirmation of chemistry

program effectiveness. These other programs include the Inservice Inspection,

Alloy 600 Aging Management, Cast Austenitic Stainless Steel Evaluation,.

Pressu'rizer Examinations, Reactor Vessel Internals Inspection, and Steam'-

Generator Integrity Programs.' Some' components, such as heat exchangers and

steam generators, have been inspected on a periodic basis providing further

evidence that the water chemistry programs are adequately managing aging

effects. If during these inspections significant abnormal conditions were noted,

including those that were the result of aging effects such as loss of material and

cracking, these conditions would have been documented under the corrective -

action program. Subsequently, actions to determine cause of the condition and

corrective actions to correct and prevent recurrence would have been taken.'--

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The GALL One Time Inspection Program XI.M32, focuses on the most

susceptible material and environment combinations in the most susceptible

locations. Items such as heat exchangers, piping and valves normally in

standby, and system low points or stagnant areas are representative of these

susceptible locations. At ANO-2, inspections have been performed in systems

such as emergency feedwater and emergency diesel generators which are

normally in standby, steam generators, condensate storage tanks, feedwater

heaters, moisture separator reheaters, chillers, main steam safety valves, and

blowdown heat exchangers. All of these components are made of susceptible

materials (stainless and carbon steel) and are exposed to environments (treated

water and steam) that would be conducive to aging effects managed by the

chemistry programs.

Many components in the steam generators have inspection activities included in

other aging management programs that provide additional assurance that

significant degradation is not occurring and that the Water Chemistry Control

Program is effective. These inspection activities include those contained in the

Inservice Inspection and Steam Generator Integrity Programs. These inspection

results of steam generator components are also applicable to the main steam,

main feedwater and emergency feedwater components which possess the same

material and environment combinations.

As additional confirmation of the effectiveness of the water chemistry programs,

the ANO-2 review of operating experience included a review of condition reports

(CRs), CR trending data, and interviews with site personnel regarding water

chemistry program operating experience. The operating experience review did

not identify component failures or significant adverse conditions that were the

result of an ineffective water chemistry program. Also, the CR trending data did

not identify recurrent component degradation occurring in the systems covered

under this aging management program. The review of CRs, CR trending data,

and personnel interviews provided additional confirmation of chemistry program

effectiveness.

The combination of inspections under the Inservice Inspection Program, the

Steam Generator integrity Program, and maintenance and routine chemistry

inspections as a whole, constitute a more thorough confirmation of water

chemistry aging management program effectiveness than would be obtained

from one-time inspections of a sample of items.

The staff has confirmed that LRA Table 3.1.2-5 lists stainless steel components of steam

generators in treated water (internal) environments, which are managed by the Water

Chemistry Control Program and also inspected under the Inservice Inspection and Steam

Generator Integrity Programs. These inspection results of steam generator components are

also applicable to the main steam, main feedwater, and emergency feedwater components that

have the same material and environment combinations. Based on the above, the staff found

that the combination of inspections under the Inservice Inspection Program, the Steam

Generator Integrity Program, and those inspection activities included in the other AMPs

constitute an adequate confirmation of the effectiveness of the Water Chemistry Control

Program. The staff therefore considers the GALL recommendations satisfied for these

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components, and RAI 3.4-3 is closed.

On the basis of its review of the information provided in the LRA and the additional information

included in the'applicant's responses to the above RAls, the staff finds that the aging effects of

the main steam system component types not addressed by the GALL Report are consistent

with industry experience for these combinations of materials and environments. The staff did

not identify any omitted aging effects. Therefore, the staff finds that the applicant has identified

the appropriate aging effects for the materials and environments associated with the

components in the main steam system.

Aging Manaaement Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement contains an adequate

description of the programs. ''

Table 3.4.2-1 of the LRA identifies the following AMPs for managing the aging effects described

above for the main steam system.

* Bolting and Torquing Activities (B.1.2)

* Flow-Accelerated Corrosion (B.1.11)

* -System Walkdown (B.1.28)

* Water Chemistry Control (B.1.30) --

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.1, 3.0.3.3.9, and

3.0.3.3.11 of this SER, respectively.

During its review, the staff determined that it needed additional information.

In LRA Table 3.4-1, Item 3.4.1-8, under "Discussion," the applicant stated that the System

Walkdown Program supplements Bolting and Torquing Activities to maintain bolting integrity in

the steam and power conversion systems. In RAI 3.4-1(4), the staff asked the-applicant to'

demonstrate that with the combination of these AMPs, the aging effects associated with closure

bolting will be adequately managed, or managed in a'manner equivalent to that described in

GALL AMP XI.M1 8, "Bolting Integrity." By letter dated April 6, 2004, the applicant stated that

the System Walkdown Program manages loss of material for closure bolting and the Bolting'

and Torquing Activities Program manages loss of mechanical closure integrity for closure

bolting. The applicant stated that visual inspections of bolting for loss of material in the System

Walkdown Program are adequate to assure that the closure bolting can perform its intended

function. This is because loss of material from external surfaces such as closure bolting is a

long-term aging effect that would be observed well before aging progressed to the point of loss

of intended function. The applicant stated that the Bolting and Torquing Activities Program

assures that proper torque values are applied to bolted closures such that loss of mechanical

closure integrity as a result of loss of pre-load because of high temperatures does not occur.

The Bolting 'and Torquing Activities and System' Walkdown Programs are plant-specific

programs and are not intended to be comparable to GALL AMP XI.M1 8, "Bolting Integrity,"

which stipulates the inservice inspection requirements of the ASME Code, Section Xl. These

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ISI requirements are included in the ANO-2 Inservice Inspection Program for Class 1, 2, and 3

bolted closures. However, these ISI requirements are focused on identifying the aging effect of

cracking. Since cracking is not an aging effect requiring management for non-Class 1 bolted

closures, the applicant did not include the Inservice Inspection Program as an AMP for the

steam and power conversion systems.

Because the bolted closures under these systems include only ASME Class 2 and 3 closure

bolting, the staff found that the applicant's response adequately addresses the staff's concern

regarding the adequacy and sufficiency of the Bolting and Torquing Activities and System

Walkdown Programs for the ANO-2 bolted closures. The applicant's response also clarified, for

closure bolting, the difference between these AMPs and the ANO-2 Inservice Inspection

Program, which primarily focuses on identifying the aging effect of cracking. Based on this

information, the staff considers RAI 3.4-1(4) to be closed.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the main steam system

component types not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the main steam

system components that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.2 Main Feedwater System

Summary of Technical Information in the Application

In Section 3.4.2.1.2 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the main feedwater system components:

* Bolting and Torquing Activities

* Flow-Accelerated Corrosion

* System Walkdown

* Water Chemistry Control

In Table 3.4.2-2 of the LRA, the applicant summarized the AMRs for the main feedwater system

components and identified which AMRs it considered to be consistent with the GALL Report.

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Staff Evaluation

The staff reviewed Table 3.4.2-2 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the main feedwater system component groups. The staff reviewed the AMR

of the main feedwater system component/materiaVenvironment/AERM combinations that are

not addressed in the GALL Report. These combinations use Notes F through J in LRA Table

-3.4.2-2, except for those with past precedents. -The staff also reviewed those combinations in

Table 3.4.2-2; with Notes A through E, which iad associated emerging issues. The staff'

confirmed that the applicant had identified all applicable AERMs and had credited appropriate

AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR Supplements

for the AMPs to ensure that the program descriptions are'adequate.'-

The applicant identified no aging effects for stainless steel components exposed to air,

including bolting, tubing, and valve component types. The GALL Report does not identify air

as an environment for these components and materials.

On the basis of current industry research and operating experience, dry air on metal will'not'

result in aging that will be of concern during the period of extended operation. The external

environments referred to are typical of ambient air (e.g., under a shelter, indoors, or in an

air-conditioned enclosure or room). Therefore, the staff concludes that there are no aging

effects requiring management for stainless steel in a dry air environment.

Aping Effects

Table 2.3.4-2 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bolting, piping, tubing, and valve.

For these component types, the applicant identifies the following materials, environments, and

AERMS:

* Carbon steel bolting in air (external) environments is subject to loss of material and loss

of mechanical closure integrity.

* Carbon steel components in air (external) and treated water greater than 220 'F

(internal) environments are subject to loss of material.

* Stainless steel bolting in air (external) environments is subject to loss of mechanical

closure integrity.

* Stainless steel components in treated water greater than 270 OF (internal) environments

are subject to'loss of material and cracking.

* Stainless steel components in air (external) environments experience no aging effects.

During its review, the staff determined that it needed additional information. :; ,I ' '' - - -

In LRA Table 3.4.1, Item 3.4.1-8, undere.Discussion," the applicant stated that for closure

bolting, the aging effect requiring management is loss of mechanical closure integrity, which

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includes a broader range of aging mechanisms than those included in this AMR line item. The

applicant also stated that it used programs other than the GALL Report's Bolting Integrity

Program. In RAI 3.4-1(1), (2), and (3), the staff asked the applicant to (1) explain the extent to

which AMR Item 3.4.1-8 deviates from the ANO-2 results; (2) clarify whether the aging effect of

"loss of mechanical closure integrity" includes loss of material and cracking, and, specifically,

what other aging effects/mechanisms are included in the ubroader range"; and (3) discuss how

it will manage each of the identified aging effects and why the approach for managing the aging

effects is adequate. Section 3.4.2.4.1 of this SER provides the staff's discussion of this RAI

and its resolution by the applicant.

In LRA Table 3.4.2-2, the applicant stated that for the main feedwater system, it uses a Water

Chemistry Control Program to manage cracking and loss of material for stainless steel

components in an environment of treated water greater than 270 0F (internal). In RAI 3.4-4, the

staff asked the applicant to explain why a supplemental inspection program is not needed to

determine the effectiveness of the Water Chemistry Control Program. The staff's discussion of

this RAI and its resolution by the applicant is similar to RAI 3.4-3 and appears in Section

3.4.2.4.1 of this SER.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the main feedwater system component types not addressed by the GALL Report are consistent

with industry experience for these combinations of materials and environments. The staff did

not identify any omitted aging effects. Therefore, the staff finds that the applicant has identified

the appropriate aging effects for the materials and environments associated with the

components of the main feedwater system.

Aging Manaaement Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement adequately describes the

program.

Table 3.4.2-2 of the LRA identifies the following AMPs for managing the aging effects described

above for the main feedwater system:

* Bolting and Torquing Activities (B.1.2)

* Flow-Accelerated Corrosion (B.1.11)

* System Walkdown (B.1.28)

* Water Chemistry Control (B.1.30)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.1, 3.0.3.3.9, and

3.0.3.2.8 of this SER, respectively.

During its review, the staff determined that it needed additional information.

In LRA Table 3.4-1, Item 3.4.1-8, under "Discussion," the applicant stated that the System

Walkdown Program supplements Bolting and Torquing Activities to maintain bolting integrity in

the steam and power conversion systems. In RAI 3.4-1(4), the staff asked the applicant to

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demonstrate that the combination of these AMPs will adequately manage the aging effects

associated with closure bolting or will manage them in a manner equivalent to that described in

GALL AMP XI.M18, -Bolting Integrity." Section 3.4.2.4.1 of this SER contains the staff's

discussion of this RAI and its resolution by the applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the main feedwater system

component types not addressed by the GALLReport. In addition, the staff finds the program

descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the main feedwater

system components that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3). -

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.3 Emergency Feedwater System

Summary of Technical Information in the ADplication

In Section 3.4.2.1.3 of the LRA, the applicant identified the materials, environments, and aging

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the emergency feedwater system components:

* Bolting and Torquing Activities

* Flow-Accelerated Corrosion

* Oil Analysis

Periodic Surveillance and Preventive Maintenance

System Walkdown

* Water Chemistry Control

In Table 3.4.2-3 of the LRA, the applicant summarized the AMRs for the emergency feedwater

system components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed Table 3.4.2-3 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the emergency feedwatersystem component groups.. The staff reviewed the

AMR of the emergency feedwater system component/materiaVenvironment/AERM

combinations that are not addressed in the GALL Report. These combinations use Notes F

through J in LRA Table 3.4.2-3, except where there were past precedents. The staff also

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reviewed those combinations in Table 3.4.2-3, with Notes A through E, for which there were

emerging issues. The staff confirmed that the applicant had identified all applicable AERMs

and had credited appropriate AMPs with managing the AERMs. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions are

adequate.

The applicant identified no aging effects for stainless steel components exposed to air,

including bolting, orifice, piping, tank, thermowell, tubing, and valve component types. The

GALL Report does not identify air as an environment for these components and materials.

On the basis of current industry research and operating experience, dry air on metal will not

result in aging that will be of concern during the period of extended operation. The external

environments referred to are typical of ambient air (e.g., under a shelter, indoors, or in an

air-conditioned enclosure or room). Therefore, the staff concludes that there are no aging

effects requiring management for stainless steel in a dry air environment.

In the case of a copper alloy heat exchanger tubesheet exposed to lube oil, the applicant

proposed to manage loss of material using the Oil Analysis Program (AMP B.1.17). The staff

reviewed and accepted the Oil Analysis Program. Section 3.0.3.3.6 of this SER documents the

staff's evaluation of this program.

The staff notes that loss of material due to pitting corrosion is an applicable aging effect for

brass, bronze, and copper materials in a lubricating oil environment at locations containing

oxygenated water with contaminants such as halide ions, particularly chloride ions. In addition,

loss of material due to galvanic corrosion in a lubricating oil environment can occur only when

materials with different electrochemical potentials are in contact in the presence of water.

The staff also notes that loss of material due to crevice corrosion can also occur in brass,

bronze, and copper materials in a lubricating oil environment at locations containing oxygenated

water. Oxygen is required for the initiation of crevice corrosion. Lube oil that is not

contaminated with water does not contain oxygen in sufficient quantities for crevice corrosion to

occur. Water contamination of lubricating oil can occur and is required for the introduction of

oxygen. Although only high-quality (water- and contaminant-free) lubricating oil is received, and

periodic sampling is performed to ensure the quality is maintained, the potential contamination

of lubricating oil makes the loss of material due to general corrosion, pitting, galvanic corrosion,

and crevice corrosion an applicable aging effect for brass, bronze, and copper materials

exposed to lubricating oil in the emergency feedwater system.

The staff further notes that loss of material due to microbiologically influenced corrosion is an

applicable aging effect for brass and copper materials exposed to lubricating oil. The applicant

treated the lubricating oil with biocides to limit the presence of microbiological organisms and,

therefore, microbiologically influenced corrosion has not been a concern for those portions of

the steam and power conversion systems that are within the scope of license renewal, and the

associated materials exposed to lubricating oil. However, the potential for microbiological

organisms to be found in lubricating oil makes microbiologically influenced corrosion an

applicable aging effect for brass and copper materials exposed to lubricating oil in the steam

and power conversion systems.

Because the Oil Analysis Program maintains oil systems free of contaminants (primarily water

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I
and particles), the staff finds that this program'adequately manages loss of material for

components exposed to lubricating oil.-

Aging Effects

Table 2.3.4-3 of the LRA lists individual system'components within the scope of license renewal

and subject to AMR. The component types that do not rely on the GALL Report for AMR

include bearing housing, bolting, equalizerpipe, filter housing, governor housing, heat -

exchanger (tubes), heat exchanger. (tubesheet), heater housing, orifice, piping, pump casing,

servo housing, sight glass, sight glass housing, steam trap, tank, thermowell, tubing, turbine

casing, and valve.

For these component types, the applicant identified the following materials,-environments, and

AERMS:

* ;Carbon steel bolting in air (external) environments is subject to loss of material and loss

*of mechanical closure integrity. In an outdoor air (external) environment, it is-also

subject to loss of material.

* Carbon steel and cast iron components in air (external) and lube oil (internal)

environments are subject to loss of material.

* Carbon steel components in steam greater than 220 0F (internal), treated water

(internal), and treated water greater than 220 IF (internal) environments are subject to

loss of material.

* Stainless steel bolting in air (external) environments is subject to loss of mechanical

closure integrity.

* - Stainless steel components in treated water (internal), lube oil (internal), and steam'.

greater than 270 IF (internal) environments are subject to loss of material and cracking.

* lCopper components in lube oil (internal) and treated water (internal) environments'are -subject to fouling and loss-of material.'! -

* Copper alloy components in lube oil (intemal) are subject to loss of material.

* Stainless steel components in air (internal and external) and outdoor air (external) environments experience no aging'effects.-

* Glass components in air (external) and lube oil (internal) environments'experience no'

aging effects. -

* Copper alloy components in air (external) 'environments experience no aging effects.

During its review, the staff determined that it needed additional information.

In LRA Table 3.4.1, Item 3.4.1-8, under "Discussion," the applicant stated that for closure

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bolting, the aging effect requiring management is loss of mechanical closure integrity, which

includes a broader range of aging mechanisms than those included in this AMR line item. The

applicant also stated that it uses programs other than the GALL Bolting Integrity Program. In

RAI 3.4-1(1), (2), and (3), the staff requested the applicant to (1) explain the extent to which

AMR Item 3.4.1-8 deviates from the ANO-2 results; (2) clarify whether the aging effect of "loss

of mechanical closure integrity" includes loss of material and cracking, and, specifically, what

other aging effects/mechanisms are included in the "broader range"; and (3) discuss how it will

manage each of the identified aging effects and why the approach to managing the aging

effects is adequate. Section 3.4.2.4.1 of this SER contains the staff's discussion of this RAI

and its resolution by the applicant.

In LRA Table 3.4.2-3, the applicant stated that for the emergency feedwater system, it uses a

Water Chemistry Control Program to manage cracking and loss of material for stainless steel

components in a steam greater than 270 OF (internal) environment. In RAI 3.4-5, the staff

requested that the applicant explain why a supplemental inspection program is not needed to

determine the effectiveness of the Water Chemistry Control Program. The staff's discussion of

this RAI and of its resolution by the applicant is similar to that for RAI 3.4-3 and appears in

Section 3.4.2.4.1 of this SER.

In LRA Table 3.4.2-3, the applicant stated that for the emergency feedwater system, it specifies

a Water Chemistry Control Program as an AMP for loss of material for stainless steel

components in treated water (internal and external) environments, and for carbon steel

components in treated water (internal) and treated water greater than 220 OF (internal)

environments. In RAI 3.4-6, the staff asked the applicant to explain why an augmented

inspection program is not needed to determine the effectiveness of the Water Chemistry

Control Program, as recommended by GALL (VIII.G.1-c, VIII.G.3-a, and VIII.G.4-b) for carbon

steel piping and valves in treated water in the emergency feedwater system and the stainless

steel condensate storage tank.

By letter dated April 6, 2004, the applicant stated that, as noted in its response to RAI 3.4-3,

since the environment and material combinations in the steam generators are the same or

more problematic than those in the emergency feedwater system, the results of steam

generator component inspections to determine the effectiveness of the Water Chemistry

Control Program are also applicable to the emergency feedwater carbon steel piping and valves

and the condensate storage tank. These inspection activities include those that are part of the

Inservice Inspection and Steam Generator Integrity Programs. Table 3.1.2-5 of the LRA lists

carbon (low alloy) and stainless steel components inspected under these programs. Based on

this information and the applicant's response to RAI 3.4-3, the staff determined that the

inspection activities conducted for components in the steam generators are applicable to the

components in the steam and power conversion systems, and the GALL recommendations of

augmenting the Water Chemistry Control Program with an inspection to determine the

effectiveness of the Water Chemistry Program are satisfied for the steam and power

conversion components. RAI 3.4-6 is therefore closed.

In LRA Table 3.4.2-3, the applicant stated that, for the emergency feedwater system, it

identified no aging effect for the glass component in lube oil (internal) environments. In RAI

3.4-7, the staff asked the applicant to provide the basis for such a conclusion. By letter dated

April 6, 2004, the applicant stated that glass is an amorphous, inorganic oxide that is mostly

silica and is cooled to a rigid condition without crystallization. It is highly resistant to corrosion

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I
- i

but is susceptible to degradation in hydrofluoric acid, caustic, and high-temperature water. The

applicant stated that lubricating oil does not contain hydrofluoric acid or caustic, and this glass

is not exposed to high-temperature water. Therefore, there are no aging effects requiring

management for the glass. The staff considered the applicant's response to adequately rule

out possible aging effects for the glass based on the material and environmental consideration.

RAI 3.4-7 is therefore closed. . ....

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the above RAls, the staff finds that the aging effects of

the emergency feedwater system component types not addressed by the GALL Report are

consistent with industry experience for these cortibinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components of the emergency feedwater system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also confirmed that the UFSAR Supplement contains an adequate

description of the program.

Table 3.4.2-3 of the LRA identifies the following -AMPs for managing the aging effects described

above for the emergency feedwater system.

* Bolting and Torquing Activities (B.1.2)

* Flow-Accelerated Corrosion (B.1.11)

* Oil Analysis (B.1.17)

* Periodic Surveillance and Preventive Maintenance (B.1.18)

* System Walkdown (B.1.28)

* Water Chemistry Control (B.1.30)

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.1, 3.0.3.3.6,

3.0.3.3.7, 3.0.3.3.9, and 3.0.3.2.8 of this SER, respectively.

During its review, the staff determined that it needed additional information.

In LRA Table 3.4-1, Item 3.4.1-8, under "Discussion," the applicant stated that the System

Walkdown Program supplements Bolting and Torquing Activities to maintain bolting integrity in

the steam and power conversion systems. In RAI 3.4-1(4), the staff requested that the

applicant demonstrate that with the combination of these AMPs, the aging effects associated

with closure bolting will be adequately managed, or managed in a manner equivalent to that

described in GALL AMP XI.M18, "Bolting Integrity." Section 3.4.2.4.1 of this SER provides the

staff's discussion of this RAI and its resolution by the applicant.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff finds that the applicant has

identified appropriate AMPs for managing the aging effects of the emergency feedwater system

component types not addressed by the GALL Report. In addition, the staff finds the program

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descriptions in the UFSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the emergency

feedwater system components that are not addressed by the GALL Report, so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 51.21(a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the steam and power conversion system components will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

steam and power conversion system components, as required by 10 CFR 54.21 (d).

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I
3.5 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 system components and component groups associated

with the following systems:

* containment and containment internals-

* auxiliary building, turbine building, and yard structures

* intake structure and emergency cooling pond

* bulk commodities

3.5.1 Summary of Technical Information in'the Application

In Section 3.5 of the LRA, the applicant provided the results of the AMR of the structures and

component supports components' and component types listed in Tables 2.4-1 through 2.4-4 of

the LRA. The'applicant also listed the materials, environments, AERMs, and AMPs'associated

with each structure and component support type.

In Table 3.5.1 of the LRA, the applicant provided a summary comparison of its AMRs with the

AMRs evaluated in the GALL Report for the structures and component supports. In Section

3.5.2.2 of the LRA, the applicant provided information concerning Table 3.5.1 components' for

which the GALL Report recommends further evaluation.

'3.5.2 Staff Ev'aluation

'The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient information

'to demonstrate that the effects of aging for the reactor system components that are within the'

scope of license renewal and subject to an AMR will be adequately managed so that the

'intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). -

The staff performed an audit and review 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 determine that the material presented in

the LRA was applicable'and that the applicabnt had identified the appropriate GALL AMPs.'--';

'Section 3.0.3 of this SER documents the staff's evaluations of the AMPs. The staff'

documented its audit findings in the audit report issued on August 19, 2004, and summarizes

them in Section 3.5.2.1 of this SER.

The staff also perf6rmed an audit of those AMRs that are consistent with the GALL Report and

for which further evaluation is recommended.' During the audit, the staff determined that the

applicant's further evaluations are consistent with'the acceptance criteria in Section 3.5.2.2 of

the SRP-LR. The staff documented its audit findings in the audit report and summarizes them

in Section 3.5.2.2 of this SER.

The staff conducted a technical review of the remaining AMRs that are not consistent with the

GALL Report. The review included evaluating whether the applicant identified all plausible

aging effects and listed the appropriate aging effects for the combinations of materials and

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environments specified. Section 3.5.2.3 of this SER documents the staff's review findings.

Finally, the staff reviewed the AMP summary descriptions in the FSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

reactor system components.

Table 3.5-1 below provides 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 3.5-1 Staff Evaluation for Structures and Component Supports System

Components in the GALL Report

'mpn-nt roup t$G<-A' AgIng Effect! ", A.''AMP IG L LO Staff Itiaii-

- . , >;t-i-- M'c'anIsm,-' *.: ^ 'Rep' I -"* '-3 ,,--- -' --+,.ap9 

Penetration Cumulative fatigu-e TLAA evaluated in Consistent with

sleeves, penetration damage (CLB accordance with GALL, which

bellows, and fatigue analysis 10 CFR 54.21(c) recommends further

dissimilar metal exists) evaluation (See

welds Section 3.5.2.2.1.6)

(Item Number

3.5.1-1)

Penetration Cracking due to Containment Containment Leak Consistent with

sleeves, bellows, cyclic loading; crack inservice inspection Rate (B.1.6), GALL, which

and dissimilar metal initiation and growth (ISI) and Containment recommends further

welds due to SCC containment leak Inservice Inspection evaluation (See

(Item Number rate test (B.1.13) Section 3.5.2.2.1.7)

3.5.1-2)

Penetration Loss of material Containment ISI Containment Consistent with

sleeves, due to corrosion and containment Inservice Inspection GALL, which

penetrations leak rate test (B.1.13), recommends no

bellows, and Containment Leak further evaluation

dissimilar metal Rate (B.1.6) (See Section

welds 3.5.2.1)

(Item Number

3.5.1-3)

Personnel airlock Loss of material Containment ISI Containment Consistent with

and equipment due to corrosion and containment Inservice Inspection GALL, which

hatch leak rate test (B.1.13), recommends no''

(Item Number Containment Leak further evaluation

3.5.1-4) Rate (B.1.6) (See Section

3.5.2.1)

Personnel airlock Loss of leak Containment leak Consistent with

and equipment tightness in closed rate test and plant GALL, which

hatch position due to technical recommends no

(Item Number mechanical wear of specifications further evaluation

3.5.1-5) locks, hinges, and (See Section

closure 3.5.2.1)

mechanisms

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I
Comporent Group' Aging EffeJ 'AMP ' in GALL.' , - In Rtio

Mech ni a.. eport' . - ..; -;

Seals, gaskets, and Loss of sealant and' Containment ISI Containment Leak Consistent with

moisture barriers leakage through and containment Rate (B.1.6) GALL, which

(Item Number containment due to leak rate test recommends no

3.5.1-6) deterioration of Join further evaluation

seals, gaskets, and (See Section

moisture barriers 3.5.2.1)

Concrete elements; Aging of accessible Containment IS1 Inservice Inspection Consistent with

foundation, dome, and inaccessible - Containment GALL, which

and wall - concrete areas due Inservice Inspection recommends further

(Item Number to leaching of (B.1.13), Structures evaluation (See -:

3.5.1-7) calcium hydroxide, Monitoring - Section 3.5.2.2.1.1)

aggressive Structures

chemical attack, Monitoring (B.1.27)

and corrosion of . -

embedded steel

Concrete elements: Cracks, distortion, Structures Structures Consistent with

foundation and increases in monitoring Monitoring - GALL, which

(Item Number component stress Structures recommends no

3.5.1-8) level due to Monitoring (B.1.27) further evaluation

settlement (See Section

3.5.2.2.1.2)

Concrete elements: Reduction in Structures Inservice Inspection Consistent with

foundation ' foundation strength monitoring - Containment . GALL, which

(Item Number due to erosion of Inservice Inspection recommends no

3.5.1-9) porous concrete (B.1.13), Structures further evaluation

subfoundation Monitoring - (See Section

Structures 3.5.2.2.1.2)

Monitoring (B.1.27)

Concrete elements: Reduction in Plant specific Inservice Inspection Consistent with

foundation, dome, strength and - Containment GALL, which

and wall: modulus due to Inservice Inspection' recommends further'

(Item Number elevated (B.1.13),:Structures evaluation (See

3.5.1-10) temperature Monitoring - ' Section 3.5.2.2.1.3)

Structures

Monitoring (B.1 27)

Prestressed Loss of prestress TLAA evaluated in Consistent with

containment: due to relaxation accordance with -GALL, which

tendons and shrinkage, creep, 10 CFR 54.21 (c) recommends further

anchorage and elevated ' . - evaluation (See

component temperature, Vr .. c .' ' Section 3.5.2.2.1.5)

(Item Number -

3.5.1-11) '

Steel elements: Loss of material Containment ISI Structures Consistent with

liner plate and due to corrosion in and containment Monitoring - GALL, which

containment shell accessible and leak rate test - Structures - recommends further,

(Item Number inaccessible areas ' ' Monitoring (B.1.27), evaluation (See

3.5.1-12) Inservice Inspection Section 3.5.2.2.1.4)

Containment

Inservice Inspection

. ..(B.1.13)

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Component Groutp Aging Effectl - AP in A P In L Staff Evaluation - Mechanisr: '. Repor lf : - -

Steel elements: Loss of material Protective coating Not Applicable at Consistent with

protected by coating due to corrosion in monitoring and ANO-2 GALL, which

(Item Number accessible areas maintenance recommends no

3.5.1-14) only further evaluation

(See Section

3.5.2.1)

Prestressed Loss of material Containment ISI Inservice Inspection Consistent with

containment: due to corrosion of -Containment GALL, which

tendons and prestressing Inservice Inspection recommends no

anchorage tendons and (B.1. 13) further evaluation

components anchorage (See Section

(Item Number components 3.5.2.1.1)

3.5.1-15)

Concrete elements: Scaling, cracking, Containment ISI Structures Consistent with

foundation, dome, and spalling due to Monitoring - GALL, which

and wall freeze-thaw; Structures recommends no

(Item Number expansion and Monitoring (B.1.27), further evaluation

3.5.1-16) cracking due to Inservice Inspection (See Section

reactor with - Containment 3.5.2.2.2.1)

aggregate Inservice Inspection

(B.1.13)

All groups except All types of aging Structures Structures Consistent with

Group 6: accessible effects monitoring Monitoring - GALL, which

interior/ exterior Structures recommends no

concrete and steel Monitoring (B.1.27) further evaluation

components (See Section

(Item Number 3.5.2.1)

3.5.1-20)

Group 1-3, 5, 7-9; Aging of Plant specific Structures Consistent with

inaccessible inaccessible Monitoring - GALL, which

concrete concrete areas due Structures recommends

components, such to aggressive Monitoring (B.1.27) further evaluation

as exterior walls chemical attack, (See Section

below grade and and corrosion of 3.5.2.2.2.2)

foundation embedded steel

(Item Number

3.5.1-21)

Group 6: all All types of aging Inspection of water- Structures Consistent with

accessible/ effects, including control structures or Monitoring - GALL, which

inaccessible loss of material due FERC/US Army Structures recommends no

concrete, steel, and to abrasion, Corp of Engineers Monitoring (B.1.27) further evaluation

earthen cavitation, and dam inspection and (See Section

components corrosion maintenance 3.5.2.1)

(Item Number

3.5.1-22)

Group 5: liners Crack initiation and Water chemistry Water Chemistry Consistent with

(Item Number growth due to SCC; and monitoring of Control (B.1.30) GALL, which

3.5.1-23) loss of material due spent fuel pool recommends no

to crevice corrosion water level further evaluation

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I
I

iComiponent Gru AngEec! APnGL .'AP lin l-RA-- Staff Evaluation.-~ - jMechanism, - Rep .

Groups 1-3, 5, 6: all Cracking due to. Masonry wall Structures Consistent with

masonry block walls restraint, shrinkage, Monitoring - GALL, which

(Item Number creep, and Masonry Wall recommends no

3.5.1-24) aggressive (B.1.26) further evaluation

environment (See Section

3.5.2.1)

Groups 1-3, 5, 7-9: Cracks, distortion, Structures Structures Consistent with

foundation and increases In monitoring Monitoring - GALL, which

(Item Number component stress Structures recommends no

3.5.1-25) level due to : * Monitoring (8.1.27) further evaluation

settlement - . (See Section

', _ 3.5.2.1)

Groups 1-3, 5-9: Reduction in Structures Structures Consistent with

foundation ' foundation strength monitoring Monitoring - GALL, which

(Item Number due to erosion of - .. Structures recommends no

3.5.1-26) porous concrete Monitoring (B.1.27) further evaluation

subfoundation I; . (See Section

;_ _ _ _ _ _ _ -___X__'__. 3.5.2.1) . -

Groups'1-5: Reduction of Plant specific Structures Consistent with

concrete strength and , . Monitoring - GALL, which

(Item Number modulus due to Structures - recommends further

3.5.1-27) elevated ; Monitoring (B.1.27) evaluation (See

temperature ' Section 3.5.2.2.1.3)

Groups 7,8: liners Crack initiation and Plant specific Not Applicable to Consistent with

(Item Number growth due to SCC; ANO-2 GALL, which

3.5.1-28) loss of material due recommends further

to crevice corrosion' ; evaluation'(See

Section

- , . , 3.5.2.2.2.1(9))

All groups: support Aging of component Structures Consistent with

members: anchor supports monitoring Monitoring - GALL, which

bolts, concrete Structures recommends no

surrounding anchor . Monitoring (B.1.27) further evaluation '

bolts, welds, grout (See Section

pad, bolted , 3.5.2.1)

connections, etc.

(Item Number

3.5.1-29) : __;,; ___ ____

Group 81.1, 81.2, Cumulative fatigue 'TLAA.evaiILated in Consistent with

and B1.3: support damage (CLB accordance with GALL, which

members: anchor fatigue analyses 10 CFR 54.21 (c) recommends further

bolts and welds exists) . . - evaluation (See

(Item Number Section 3.5.2.2.3.2).

3.5.1-30) . . *

All groups: support Loss of material Boric acid corrosion Boric Acid Consistent with

members: anchor due to boric acid Corrosion GALL, which

bolts and welds corrosion . Prevention (B.1.3) recommends no

(Item Number . . further evaluation

3.5.1-31) (See Section

._ 3.5.2.1)

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EffetGp Aging5Efet - * AMP In GALu - 4-AMP L p S i al atiAui

Mechanism Report I{ '' *?';

Groups B1.1, B1.2, Loss of material 151 Inservice Inspection Consistent with

and B1.3: support due to -Inservice GALL, which

members: anchor environmental Inspection (B.1.14) recommends no

bolts, welds, spring corrosion; loss of further evaluation

hangers, guides, mechanical function (See Section

stops, and vibration due to corrosion, 3.5.2.1) isolators distortion, dirt,

(Item Number overload, etc.

3.5.1-32)

Group B1.1: high Crack initiation and Bolting integrity Inservice Inspection Consistent with

strength low-alloy growth due to SCC -Inservice GALL, which

bolts Inspection (B.1.14), recommends no

(Item Number Borc Acid further evaluation

3.5.1-33) Corrosion (See Section

Prevention (B.1.3) 3.5.2.1)

The staff's review of the ANO-2 structures and component supports system and associated

components followed one of several approaches. One approach, documented in Section

3.5.2.1 of this SER, involves the staff's audit and review of the AMR results for components in

the structures and component supports system that the applicant indicated are consistent with

the GALL Report and do not require further evaluation. The second approach, documented in

Section 3.5.2.2 of this SER, involves the staff's audit and review of the AMR results for

components in the structures and component supports system that the applicant indicated are

consistent with the GALL Report and for which further evaluation is recommended. A third

approach, documented in Section 3.5.2.3 of this SER, involves the staff's technical review of

the AMR results for components in the structures and component supports system that the

applicant indicated are not consistent with the GALL Report or are not addressed in the GALL

Report. Section 3.0.3 of this SER documents the staff's review of AMPs that are credited to

manage or monitor aging effects of the structures and component supports system

components.

3.5.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application

In Section 3.5.2.1 of the LRA, the applicant identified the materials, environments, and AERMs.

The applicant identified the following programs that manage the aging effects related to the

structures and component supports components:

* Boric Acid Corrosion Prevention Program

* Containment Leak Rate Program

* Inservice Inspection-Containment Inservice Inspection (IWE and IWL) Program

* Inservice Inspection (IWF) Program

* Structures Monitoring Program

* Structures Monitoring-Masonry Wall Program

* Water Chemistry Control Program

* Service Water Integrity Program

* Periodic Surveillance and Preventive Maintenance Program

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Fire Protection Program

In Tables 3.5.2-1 through 3.5.2-4 of the LRA,'the'applicant provided a summary of AMRs for

the structures and component supports systems and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation

In Tables 3.5.2-1 through 3.5.2-4 of the LRA,Ithe applicant provided a summary of AMRs for

the containment and containment internals, auxiliary building, turbine building, yard structures,'

intake structure, emergency cooling'pond,`adrd bulk commodities components and identified " which AMRs it considered to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the'applicant has claimed

consistency with the GALL Report, and fdr'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 Reportrcomponent groups are 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 c'onsistent with the GALL: Report.'

Note A indicates that the AMR line item is consistent with the GALL Report for the 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 determine consistency with

the GALL Report and the validity of the AMR for the site-specific conditions.i

Note B indicates that the AMR line item is consistent with the GALL Report for the component,

material, environment, and aging effect. ' I addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to determine

consistency with the GALL Report. The staff confirmed that it has reviewed and accepted the

identified exceptions to the GALL AMPs. `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

is valid for the site-specific conditions.

Note C indicates that the'component for'the AMR line item is different, but consistent with the

GALL Report for the 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 could not

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 naterial, environment,

aging effect, and AMP as the component under review. The staff audited these line items to

determine consistency with the GALL Report.>' The staff also determined whether the AMR line

item of the different component applies to the component under review and whether the AMR is

valid for the site-specific conditions.' '-

Note D indicates that the component for the AMR line item is different, but consistent with the

GALL'Report for the 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,

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determine consistency with the GALL Report. The staff noted whether the AMR line item of

the different component applies to the component under review. The staff confirmed that it

reviewed and accepted the identified exceptions to the GALL AMPs. 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 is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for the material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to determine consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review, discussed below, to confirm the applicant's claim that

certain identified AMRs are consistent with the staff-approved AMRs in the GALL Report. The

staff reviewed the information provided in the LRA and program basis documents, which are

available at the applicant's engineering office. The staff did not repeat its review of the matters

described in the GALL Report. However, the staff did determine that the material presented in

the LRA is applicable and that the applicant has identified the appropriate GALL Report AMRs.

3.5.2.1.1 Structures and Components Supports, Containment, and Containment Internals

The staff reviewed Table 3.5.1, Item 3.5.1-3 of the LRA, and associated AMRs consistent with

the GALL Report.

In Table 3.5.2-1 of the LRA, the applicant associated the incorrect Table 3.5.1, Item 3.5.1-3, for

loss of material of carbon steel tendon anchorage and the tendon wires component type (page

3.5-27). The staff requested that the applicant revise the LRA Table 3.5.2-1 line entry with the

correct Table 3.5.1 item number.

By letter dated March 24, 2004, the applicant submitted a clarification to reference the correct

Table 3.5.1, Item 3.5.1-15, to anchorage and tendon wires. The applicant also submitted a

clarification that Table 3.5.1, Item 3.5.1-15 (LRA page 3.5-17), should credit the Inservice

Inspection (IWL) Program rather than the Inservice Inspection (IWE) Program in the discussion

column.

The staff reviewed the Inservice Inspection-Containment Inservice Inspection Program (AMP

B.1.13) and determined that the ASME Code, Section Xi, Subsection IWL Program manages

the containment anchorage and tendon wires. On the basis of its review, the staff concludes

that this line item is acceptable.

3.5.2.1.2 Structures and Components Supports, Bulk Commodities

In Table 3.5.2-4 (page 3.5-38) of the LRA, the applicant associated component type UHVAC

missile barrier" with the GALL Report, Volume 2, Chapter III.A2.2-a. The staff requested that

the applicant revise the LRA Table 3.5.2-4 line entry with the correct GALL Report, Volume 2,

item number.

By letter dated March 24, 2004, the applicant submitted a clarification to reference the correct

GALL Report, Volume 2, Item IlI.A3.2-a. The staff reviewed the GALL Report, Volume 2, Item

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IlI.A3.2-a, and determined that the HVAC missile barrier component group should reference the

GALL Report, Volume 2, Chapter 1II, for Group 3 structures rather than Chapter Il, Group 2

structures. On this basis, the staff concludes that this line item is acceptable.

On the basis of its audit and review, 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).

Conclusion

The staff determined 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 associated aging effects' .On the basis of its review, the staff finds

that the applicant has demonstrated that the effects of aging for these components will be

adequately managed so that their intended functions will be maintained consistent with the CLB

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

Summarv of Technical Information in the ADDlication

*, .1- ; ; .

In Section 3.5.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for structures and component supports. The applicant

provided information concerning how it will manage the following aging effects: . :

* (PWR containments) aging of inaccessible concrete areas

* (PWR containments) cracking, distortion,-and increase in component stress levels due

to settlement; reduction of foundation strength due to erosion of porous concrete

subfoundations, if not covered by Structures Monitoring Program I

(PWR containments) reduction of strength and modulus of concrete structures due to

elevated temperature -

* (PWR containments) loss of material due to corrosion in inaccessible areas of steel

containment shell or liner plate

. . .

* (PWR containments) loss of prestress due to relaxation, shrinkage, creep, and elevated

temperature

* (PWR containments) cumulative fatigue damage

* (PWR containments) cracking due to cyclic loading and SCC

* (Class I structures) aging of structures not covered by Structures Monitoring Program

* (Class I structures) aging management of inaccessible areas

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* (component supports) aging of supports not covered by Structures Monitoring Program

* (component supports) cumulative fatigue damage due to cyclic loading

* quality assurance for aging management of nonsafety-related components

Staff Evaluation

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 reviewed the applicant's evaluation to determine whether it adequately

addressed these issues. In addition, the staff audited the applicant's further evaluations against

the criteria contained in Section 3.5.2.2 of the SRP-LR. The ANO-2 ANO-2 Audit and Review

Report provides details of the staff's audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

3.5.2.2.1 PWR Containments

The staff reviewed Section 3.5.2.2.1 of the LRA against the criteria in Section 3.5.2.2.1 of the

SRP-LR, which addresses several areas discussed below.

3.5.2.2.1.1 Aging of Inaccessible Concrete Areas. In Section 3.5.2.2.1.1 of the LRA, the

applicant addressed aging of inaccessible concrete areas for the containment.

For inaccessible portions of the containment structure, 10 CFR 50.55a(b)(2)(ix) requires that

the licensee evaluate the acceptability of inaccessible areas when conditions exist in accessible

areas that could indicate the presence of, or result in, degradation to inaccessible areas.

The GALL Report recommends GALL AMP XI.S2, "ASME Section Xl, Subsection IWL," for

managing the aging of the accessible portions of the containment structures. The applicant

addressed this issue with LRA AMP B.1.13, "Inservice Inspection-Containment Inservice

Inspection," which is evaluated in Section 3.0.3.3.4 of this SER. Subsection IWL exempts from

examination those portions of the concrete containment that are inaccessible (e.g., foundation,

belowgrade exterior walls, or concrete covered by liner).

The applicant also credited the Structures Monitoring Program (AMP B.1.27), where accessible

areas are monitored for evidence of aging effects that may apply to containment structures.

Section 3.0.3.1 of this SER evaluates this program, which is consistent with GALL AMP XI.S6,

"Structures Monitoring Program." It is also used for the examination of belowgrade concrete

when it is exposed by excavation.

The GALL Report, Volume 2, Chapter II, Table Al (as modified by ISG-3), recommends further

evaluation to manage the aging effects for containment concrete components located in

inaccessible areas if the aging mechanisms of (1) freeze-thaw, (2) leaching of calcium

hydroxide, (3) aggressive chemical attack, (4) reaction with aggregates, or (5) corrosion of

embedded steel are significant. Possible aging effects for containment concrete structural

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components from these five aging mechanisms include cracking; change in material properties,

and loss of material.

(1) Freeze-thaw

Section 3.5.2.2.1.1 of the SRP-LR does not address freeze-thaw as an aging mechanism for

concrete containments because the GALL-Report does not recommend further evaluation.

However, ISG-3 clarifies the staff position that further evaluation is appropriate if the applicant's

facility is subject to moderate to severe weathering conditions, unless the concrete meets

certain specifications and subsequent inspections have confirmed that the aging mechanism

has not caused degradation of the concrete.

ANO-2 is located in a region considered to be subject to moderate weathering conditions. In

the LRA, the applicant stated that ANO-2 concrete structures are designed in accordance with

American Concrete Institute (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

The applicant stated in the LRA that ANO-2 concrete also meets the requirements of ACI

201.2R-77, "Guide to Durable Concrete." Both ACI 318-63 and ACI201.2R-77 use the same'

ASTM standards for selection, application, and testing of concrete.

The staff interviewed members of the applicant's technical staff and reviewed relevant operating

experience to confirm that loss of material due to freeze-thaw has not been observed, either.

through the Containment Inservice Inspection Program or the Structures Monitoring Program.

Because concrete that satisfies the requirements of ACI 318-63 will meet the requirements of

ISG-3, and on the basis of an audit of operating experience evaluated under the Containment

Inservice Inspection Program and Structures Monitoring Program, the staff finds that the ;

Containment Inservice Inspection Program will adequately manage the loss of material and

cracking due to freeze-thaw.

(2) Leaching of calcium hydroxide : .

Section 3.5.2.2.1.1 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability caused by the leaching of calcium hydroxide could occur in inaccessible areas of

PWR concrete and steel containments. The GALL Report, as updated by ISG-3, recommends

further evaluation of plant-specific programs to manage the aging effects for inaccessible areas

if specific criteria cannot be satisfied.

The GALL Report states that leaching of calcium hydroxide becomes significant only if the

concrete is exposed to flowing water. Even if reinforced concrete is exposed to flowing water,

such leaching is not significant if the concrete is constructed to ensure that it is dense, well

cured, and has low permeability, and that cracking is well controlled.

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The applicant stated in the LRA that ANO-2 concrete structures are designed in accordance

with ACl 318-63 and meet the requirements of ACI 201.2R-77.

The staff finds that because ACI 318 provides assurance that the recommendations of the

GALL Report and ISG-3 are met, leaching of calcium hydroxide is not significant at ANO-2.

Therefore, the staff concludes that the Containment Inservice Inspection Program will be

sufficient for management of increases in porosity and permeability due to this aging

mechanism. A plant-specific AMP is not required to address this aging effect.

(3) Aggressive chemical attack

Section 3.5.2.2.1.1 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability caused by aggressive chemical attack could occur in inaccessible areas of PWR

concrete and steel containments. The GALL Report recommends further evaluation of

plant-specific programs to manage the aging effects for inaccessible areas if specific

recommendations of the GALL Report and updated in ISG-3 cannot be satisfied.

The GALL Report, as updated by ISG-3, states that aggressive chemical attack is not

significant unless pH is less than 5.5, chlorides are greater than 500 parts per million (ppm), or

sulfates are greater than 1500 ppm. In addition, ISG-3 states that a plant-specific program is

required to examine representative samples of belowgrade concrete when excavated for any

reason.

The applicant stated in the LRA that the belowgrade environment is not aggressive (i.e.,

pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm). In

addition, the staff noted that the applicant used the Structures Monitoring Program for the

examination of belowgrade concrete when it is exposed by excavation.

On the basis of the information provided by the applicant in the LRA and the guidelines

provided in the SRP-LR, the GALL Report, and ISG-3, the staff finds that increases in porosity

and permeability, loss of material (e.g., spalling and scaling), and cracking caused by

aggressive chemical attack are not significant for concrete in inaccessible areas. The staff

finds that an appropriate plant-specific program for examination of belowgrade concrete has

been identified.

(4) Reaction with aggregates

Section 3.5.2.2.1.1 of the SRP-LR does not address reaction with aggregates as an aging

mechanism for concrete containments because the GALL Report does not recommend further

evaluation. However, ISG-3 clarifies the staff position that further evaluation is appropriate if

investigations, tests, or examinations have demonstrated that the aggregates are reactive.

The applicant stated in the LRA that ANO-2 concrete structures are designed in accordance

with ACI 318-63 and meet the requirements of ACI 201 .2R-77. The ACI standards call for the

testing of aggregates at the time of construction. Through interviews with the applicant's

technical staff, the staff confirmed that the results of those tests show that the aggregates used

for concrete containment at ANO-2 are not reactive.

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(5) Corrosion of embedded steel

Section 3.5.2.2.1.1 of the SRP-LR states that loss of material due to corrosion of embedded

steel could occur in inaccessible areas of PWR concrete and steel containments. The GALL.

Report (updated in ISG-3) recommends further evaluation of plant-specific programs to manage

the aging effects for inaccessible areas if specific recommendations of the GALL Report cannot

be satisfied.

For cracking, loss of bond, and loss of material (e.g., spalling and scaling) due to'the corrosion

of embedded steel, the GALL Report states that a plant-specific program is only required if the

belowgrade environment is aggressive. In addition, ISG-3 states that a plant-specific program

is required to examine representative samples of belowgrade concrete when excavated for any

reason.

The applicant stated in the LRA that the belowgrade environment is not aggressive'(i.e.,

pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm). In

addition, the staff noted that the applicant used the Structures Monitoring Program for the

examination of belowgrade concrete when it is exposed by excavation.

Through interviews with the applicant's technical staff, the staff determined that the

environment at the time of construction was not aggressive and, on the basis of subsequent

testing, the environment has' remained within the limits identified in the GALL Report. The staff

finds that, in accordance with the recommendations of the GALL Report, this aging effect is not

significant and is adequately managed.

The staff reviewed the results of the applicant's AMR for inaccessible concrete areas. 'On the'

basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of aging of inaccessible concrete areas for containment, as -

recommended in the GALL Report and ISG-3.' The staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.5.2.2.1.2 Cracking. Distortion, and Increase in Component Stress Level due to Settlement:

Reduction of Foundation Strength due to Erosion of Porous Concrete Subfoundations.' If Not

Covered by Structures Monitoring Program. In Section 3.5.2.2.1.2 of the LRA, the applicant

addressed (1) cracking, distortion, and increase incomponent stress level due to settlement

and (2) reduction of foundation strength due to erosion of porous concrete subfoundations in

the containment. The applicant used the Structures Monitoring Program (AMP B.1.27), which

monitors accessible areas for evidence of aging'effects that may apply to containment -

structures. 'Section 3.0.3.1 of this SER evaluates this program, which is consistent with GALL

AMP XL.S6, "Structures Monitoring Program."!. ,

Section 3.5.2.2.1.2 of the SRP-LR states that cracking, distortion, and increase in component

stress level due to settlement could occur in PWR concrete and steel containments. In

addition; reduction of foundation strength due to erosion of porous concrete subfoundations

could occur in all types of PWR containments.: Some plants may rely on a dewatering system

to lower the site ground water level. If the plant's CLB credits a dewatering system, the' GALL

Report recommends verification of the continued functionality of the dewatering system during

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the period of extended operation. The GALL Report recommends no further evaluation if this

activity is included in the scope of the applicant's structures monitoring program.

The applicant stated in the LRA that ANO-2 does not rely on a dewatering system for control of

settlement because seismic Category 1 structures are founded on sound bedrock. Concrete

within 5 feet of the highest known ground water level is protected by membrane waterproofing,

which protects the containment building concrete against exposure to ground water.

Consequently, IN 97-11 does not identify ANO-2 as a plant susceptible to erosion of porous

concrete subfoundations. Ground water was not aggressive during plant construction, and no

changes in ground water conditions have been observed. Finally, the applicant has included

these components within the plant-specific structures monitoring program, which will confirm

that these aging effects are adequately managed.

The staff reviewed the AMR results involving management of aging effects resulting due to

settling and erosion of porous concrete subfoundations and confirmed that the Structures

Monitoring Program addresses each of the affected SCs. On the basis of this review, the staff

finds that the applicant has appropriately evaluated AMR results involving cracking, distortion,

and increase in component stress level due to settlement and reduction of foundation strength

due to erosion, as recommended in the GALL Report.

3.5.2.2.1.3 Reduction of Strength and Modulus of Concrete Structures due to Elevated

Temperature. In Section 3.5.2.2.1.3 of the LRA, the applicant addressed reduction of strength

and modulus of concrete structures due to elevated temperature in containments.

Section 3.5.2.2.1.3 of the SRP-LR states that reduction of strength and modulus of elasticity

due to elevated temperatures could occur in PWR concrete and steel containments. The GALL

Report calls for a plant-specific AMP and recommends further evaluation if any portion of the

concrete containment components exceeds specified temperature limits (i.e., general area

temperature 66 0C (150 OF) and local area temperature 93 OC (200 OF)).

The applicant stated in the LRA that, during normal operation, all concrete areas within

containment are below 66 'C (150 0F) ambient temperature. The applicant concluded that its

containment concrete structures are not subject to changes in material properties due to

elevated temperature. The applicant has included these components within the scope of

AMP B.1.27, "Structures Monitoring-Structures Monitoring," and AMP B.1.13, "Inservice

Inspection-Containment Inservice Inspection," to monitor for indications of change in material

properties for containment concrete aging effects.

The staff reviewed the AMR results involving management of aging effects resulting from

elevated temperature and confirmed that the Containment Inservice Inspection Program and

Structures Monitoring Program address each of the affected SCs. On the basis of this auditand review, the staff finds that the applicant has appropriately evaluated AMR results involving

reduction of strength and modulus due to elevated temperature, as recommended in the GALL

Report.

In addition, because the concrete is not exposed to elevated temperatures, the staff finds that

the plant-specific AMPs are acceptable for management of this aging effect, and no further

evaluation is required.

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The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be'maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.1.4 Loss of Material due to Corrosion in Inaccessible Areas of Steel Containment Shell

or Liner Plate. In Section 3.5.2.2.1.4 of the LRA, the applicant addressed loss of material dueto corrosion in inaccessible areas of the steel containment shell or the steel liner'plate for the

containment. -

Section 3.5.2.2.1.4 of the SRP-LR states that loss'of material due'to corrosion could occur in

inaccessible areas of the steel containment shell or the steel liner plate for all types of PWR

containments. The GALL Report recommends further evaluation of plant-specific programs to

manage this aging effect for inaccessible areas if the following four specific recommendations

of the GALL Report cannot be satisfied:

(1) Concrete meeting the requirements of ACI 318 or 349 and the guidance of ACI 201 .2R

was used for the containment concrete in contact with the embedded containment shell

or liner. - -

(2) The accessible concrete is monitored to ensure that it is free of penetrating cracks that

provide a path for water seepage to the surface of the containment shell or liner.

(3) The accessible'portion of the moisture barrier, at the junction where the shell or liner

becomes embedded, is subject to aging management activities in accordance with IWE

requirements.

(4) Borated water spills and water ponding on the containment concrete floor are not

common and, when detected, are cleaned up in a timely manner.

The applicant stated in the LRA that the containment concrete in contact with the steel liner

plate is designed in accordance with ACI 318-63 and meets the requirements of

ACI 201 .2R-77. Accessible concrete is monitored for cracks under the Structures Mo'nitoring

Program, evaluated in Section 3.0.3.1 of this SER. The accessible portions of the steel liner

plate and moisture barrier where the liner becomes embedded are inspected in accordance with

the Containment Inservice Inspection Program (IWE), evaluated in Section 3.0.3.3.4 of this

SER. Spills (e.g., borated water spill) are cleaned up in a timely manner. The aging effect of

loss of material due to corrosion has not been significant for this liner plate.

Since the applicant satisfied all of the recommendations of the GALL Report, the staff finds that

no additional plant-specific AMP is required to manage inaccessible areas of the steel

containment liner plate; .

3.5.2.2.1.5 Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature.

As stated in the SRP-LR, loss of prestress due to relaxation, shrinkage, creep, and elevated

temperature is a TLAA, as defined in .10 CFR 54.3.' All TLAAs must be evaluated in accordance

with 10 CFR 54.21 (c)(1). Section 4.5 of this SER documents the staff's review of the

applicant's evaluation of this TLAA. In performing this review, the staff followed the guidance in

Section 4.5 of the SRP-LR.

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3.5.2.2.1.6 Cumulative Fatigue Damage. As stated in the SRP-LR, fatigue is a TLAA, as

defined in 10 CFR 54.3. All TLAAs must be evaluated in accordance with 10 CFR 54.21 (c)(1).

Section 4.6 of this SER documents the staff's review of the applicant's evaluation of this TLAA.

In performing this review, the staff followed the guidance in Section 4.6 of the SRP-LR.

3.5.2.2.1.7 Cracking Caused by Cyclic Loading and Stress-Corrosion Cracking. In Section

3.5.2.2.1.7 of the LRA, the applicant addressed aging mechanisms that can lead to the cracking

of penetration sleeves and penetration bellows, such as cyclic loads and SCC.

Section 3.5.2.2.1.7 of the SRP-LR states that cracking of containment penetrations (including

penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading or

SCC could occur in containments. The SRP-LR recommends further evaluation of inspection

methods to detect cracking caused by cyclic loading and SCC since visual testing (VT)-3

examinations may be unable to detect this aging effect.

(1) Cracking caused by SCC

The GALL AMP XI.S1, "ASME Section Xl Subsection IWE," covers inspection of these items

under examination categories E-B, E-F, and E-P (pressure tests in Appendix J to

10 CFR Part 50). Title 10, Section 50.55a, of the Code of Federal Regulations

(10 CFR 50.55a) identifies examination categories E-B and E-F as optional during the current

term of operation. For the extended period of operation, examination categories E-B and E-F

and additional appropriate examinations to detect SCC in bellows assemblies and dissimilar

metal welds are warranted to address this issue.

To manage this aging effect, the applicant used the Containment Leak Rate Program (AMP

B.1.6) and the Containment Inservice Inspection Program (AMP B.1.13). Section 3.0.3.1 of this

SER documents the staff's evaluation of the Containment Leak Rate Program. The staff

determined that the Containment Inservice Inspection Program AMP B.1.13, evaluated in

Section 3.0.3.3.4 of this SER, required enhancement and additional appropriate examinations

to detect SCC in bellows assemblies and dissimilar metal welds using examination categories

E-B and E-F.

In a letter dated April, 14, 2004, the staff asked the applicant to provide additional information

regarding the containment pressure boundary bellows, relevant operating experience, and.

methods used to detect their age-related degradation. The staff noted that the Containment

Inservice Inspection Program and Containment Leak Rate Program cannot detect cracking

caused by SCC (see NRC IN 92-20, "Inadequate Local Leak Rate Testing").

By letter dated May 19, 2004, the applicant stated that the penetration bellows. (LRA Table

3.5.1, Item 3.5.1-3) pertains to carbon steel penetrations, which are not susceptible to SCC and

are consistent with the GALL Report, but do not require further evaluation. In addition, the

applicant stated that LRA Table 3.5.1, Item 3.5.1-2, addresses SCC of stainless steel

penetration bellows. The applicant further stated that bellows are not used for piping system

containment penetrations at ANO-2 and that Item 3.5.1-2 applies to the fuel transfer tube

sleeve, but not to the bellows, since the bellows are not part of the containment penetration

boundary.

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Because the bellows are not used for piping system containment penetrations, and based on,

the staff's review of the applicant's response, the staff finds this acceptable.

(2) Cracking caused by cyclic loading

As stated in the SRP-LR, cracking caused by cyclic loading of the liner plate and penetrations is

a TLAA, as defined in 10 CFR 54.3. All TLAAs must be evaluated in accordance with

10 CFR 54.21(c)(1). Section 4.6 of this SER documents the staff's review of the applicant's..

evaluation. In performing this review, the staff followed the guidance in Section 4.6 of the SRPLR. - -- ,

3.5.2.2.2 Class 1 Structures

The staff reviewed Section 3.5.2.2.2 of the LRA against the criteria in Section 3.5.2.2.2 of the

SRP-LR, which addresses several areas discussed below.

3.5.2.2.2.1 Aging of Structures Not Covered by Structures Monitoring Program. In Section

3.5.2.2.2.1 of the LRA, the applicant addressed aging of Class 1 structures not covered by the

Structures Monitoring Program. ,

Section 3.5.2.2.2.1 of the SRP-LR states that the GALL Report recommends further evaluation

of certain structure/aging effect combinations if they are not covered by the Structures,

Monitoring Program. As described in Chapter III of the GALL Report, this includes (1) scaling,

cracking, and spalling due to repeated freeze-thaw for Group 1-3, 5, and 7-9 structures, (2).,,

scaling, cracking, spalling, and increase in porosity and permeability caused by leaching of

calcium hydroxide and aggressive chemical attack for Group 1-5 and 7-9 structures, (3)

expansion and cracking due to reaction with aggregates for Group 1-5 and 7-9 structures, (4)

cracking, spalling, loss of bond, and loss of material due to corrosion of embedded steel for

Group 1-5 and 7-9 structures, (5) cracks, distortion, and increase in component stress level.

caused by settlement for Group 1-3, 5, and 7-9 structures, (6) reduction of foundation strength

caused by erosion of porous concrete subfoundations for Group 1-3 and 5-9 structures, (7)

loss of material due to corrosion of structural steel components for Group 1-5 and 7-8

structures, (8) loss of strength and modulus of concrete structures due to elevated - temperatures for Groups 1-5, and (9) crack initiation and growth due to SCC and loss of

material due to crevice corrosion of stainless steel liner for Group 7-8 structures. Further

evaluation is necessary only for structure/aging effect combinations not covered by the

Structures Monitoring Program.

Subsection 3.5.2.2.1.2 of the SRP-LR provides technical details of the aging management

issue for structure/aging effect combinations (5) and (6) above. Subsection 3.5.2.2.1.3 of the

SRP-LR gives the details for item (8) above.--:,,,-;

In Table 3.5-1, Item 20, the applicant credited its Structures Monitoring Program for all types of

aging effects and all component groups (except Group 6) of accessible interior and exterior

concrete and steel components of Class 1 structures. Section 3.0.3.1 of this SER evaluates

this program. Additional discussion of specific structure/aging effect combinations follows.

(1) Freeze-thaw -

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Section 3.5.2.2.1.2 of the SRP-LR does not address freeze-thaw as an aging mechanism for

concrete containments, because no further evaluation is recommended in the GALL Report.

However, ISG-3 clarifies the staff position that further evaluation is appropriate if the applicant's

facility is subject to moderate to severe weathering conditions, unless the concrete meets

certain specifications and subsequent inspections have confirmed that the aging mechanism

has not caused degradation of the concrete.

ANO-2 is located in a region considered to be subject to moderate weathering conditions. In

the LRA, the applicant stated that ANO-2 structures are designed in accordance with ACI

318-63, 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

In addition to ACI 318-63, ANO-2 concrete also meets the requirements of ACI 201.2R-77.

Both ACI 318-63 and AC1201.2R-77 use the same ASTM standards for selection, application,

and testing of concrete.

The staff interviewed members of the applicant's technical staff and reviewed relevant operating

experience to confirm that loss of material due to freeze-thaw has not been observed, either

through the Containment Inservice Inspection Program or the Structures Monitoring Program.

Because concrete that satisfies the requirements of ACI 318-63 will meet the requirements of

ISG-3, and on the basis of an audit of operating experience evaluated under the Structures

Monitoring Program, the staff finds that the Structures Monitoring Program will adequately

manage the loss of material and cracking due to freeze-thaw.

(2)(a) Leaching of calcium hydroxide

Section 3.5.2.2.2.1 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability due to leaching of calcium hydroxide could occur in inaccessible areas of PWR

concrete and steel containments. The GALL Report, as updated by ISG-3, recommends further

evaluation of plant-specific programs to manage the aging effects for inaccessible areas

exposed to flowing water, unless the requirements of ACI 201.2R are met.

The GALL Report states that leaching of calcium hydroxide becomes significant only if the

concrete is exposed to flowing water. Even if reinforced concrete is exposed to flowing water,

such leaching is not significant if the concrete is constructed to ensure that it is dense, well

cured, and has low permeability, and that cracking is well controlled.

The applicant stated in the LRA that concrete structures are designed in accordance with ACI

318-63 and meet the requirements of ACI 201.2R-77.

The staff finds that the use of ACI 318 provides assurance that the recommendations of the

GALL Report and ISG-3 are met and leaching of calcium hydroxide is not significant at ANO-2.

Therefore, the staff concludes that the Structures Monitoring Program will sufficiently manage

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increases in porosity and permeability due to this aging mechanism. A plant-specific AMP is

not required to address this aging effect.

(2)(b) Aggressive chemical attack

Section 3.5.2.2.2.1 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability due to aggressive chemical attack could occur in inaccessible areas of Class 1

structures. The GALL Report recommends further evaluation of plant-specific programs to

manage the aging effects for inaccessible areas if specific recommendations of the GALL

Report and the updates in ISG-3 cannot be satisfied...

The GALL Report, as updated by ISG-3, states that aggressive chemical attack is not

significant unless pH is less than 5.5, chlorides are greater than 500 ppm, or sulfates are

greater than 1500 ppm. In addition, ISG-3 states that a plant-specific program is required to;

examine representative samples of belowgrade concrete when excavated for any reason.

The applicant stated in the LRA that the belowgrade environment is not aggressive (i.e.,

pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm). In

addition, the staff noted that the applicant used the Structures Monitoring Program for the

examination of belowgrade concrete when it is exposed by excavation.

On the basis of the information given in the LRA and the guidelines provided in the SRP-LR, the

GALL Report, and ISG-3, the staff finds that increases in porosity and permeability, loss of

material (e.g., spalling and scaling), and cracking caused by aggressive chemical attack are not

significant for concrete in inaccessible areas; The staff finds that the applicant identified an

appropriate plant-specific program for examination of belowgrade concrete (specifically, an

enhancement to the Structures Monitoring Program).

(3) Reaction with aggregates

Section 3.5.2.2.2.1 of the SRP-LR does not address reaction with aggregates as an aging

mechanism for concrete containments, because no further evaluation is recommended in the,

GALL Report. However, ISG-3 clarifies the staff position that further evaluation is appropriate if

investigations, tests, or examinations have demonstrated that the aggregates are reactive.

The applicant stated in the LRA that ANO-2 concrete structures were designed in accordance

with ACI 318-63 and meet the requirements of ACI 201 .2R-77. The ACI standards call for the

testing of aggregates at the time of construction. -

Through interviews with the applicant's technical staff, the staff confirmed that the results of

those tests showed that the aggregates used for concrete Class 1 structures at ANO-2 are not

reactive.

(4) Corrosion of embedded steel

Section 3.5.2.2.2.1 of the SRP-LR states that loss of material due to corrosion of embedded

steel could occur in inaccessible areas of.Class 1 structures. The GALL Report (updated in

ISG-3) recommends further evaluation of plant-specific programs to manage the aging effects

for inaccessible areas if specific recommendations of the GALL Report cannot be satisfied.

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For cracking, loss of bond, and loss of material (e.g., spalling and scaling) due to corrosion of

embedded steel, the GALL Report states that a plant-specific program is only required if the

belowgrade environment is aggressive. In addition, ISG-3 states that a plant-specific program

is required to examine representative samples of belowgrade concrete when excavated for any

reason.

The applicant stated in the LRA that the belowgrade environment is not aggressive. In

interviews with the applicant's technical staff, the staff determined that the environment at the

time of construction had a measured pH greater than 5.5, chlorides less than 500 ppm, and

sulfates less than 1500 ppm, and, on the basis of subsequent testing, it has remained within

these limits.

The staff finds that, in accordance with the recommendations of the GALL Report, this aging

effect is not significant and is adequately managed by the enhanced Structures Monitoring

Program. Section 3.0.3.1 of this SER documents the staff's evaluation of this program.

(5) Settlement

Section 3.5.2.2.2.1 of the SRP-LR refers to Section 3.5.2.2.1.2 for a discussion of settlement.

Section 3.5.2.2.1.2 of the SRP-LR states that cracking, distortion, and increase in the

component stress level due to settlement could occur in Class 1 structures. Some plants may

rely on a dewatering system to lower the site ground water level. If the plant's CLB credits a

dewatering system, the GALL Report recommends verification of the continued functionality of

the dewatering system during the period of extended operation. The GALL Report

recommends no further evaluation if this activity is included in the scope of the applicant's

structures monitoring program.

The applicant stated in the LRA that ANO-2 does not rely on a dewatering system for control of

settlement because Class 1 structures are founded on sound bedrock. Concrete within 5 feet

of the highest known ground water level is protected by membrane waterproofing, which

protects the containment building concrete against exposure to ground water. Consequently,

IN 97-11 does not identify ANO-2 as a plant susceptible to erosion of porous concrete

subfoundations. Ground water was not aggressive during plant construction, and no changes

in ground water conditions have been observed. The applicant also included these components

within the plant-specific structures monitoring program, which will confirm that these aging

effects are adequately managed.

The staff reviewed the AMR results involving management of aging effects resulting from

settling and erosion of porous concrete subfoundations and confirmed that the Structures

Monitoring Program addresses each of the affected SCs. On the basis of this review, the staff

finds that the applicant has appropriately evaluated AMR results involving cracking, distortion,

and increase in the component stress level due to settlement and reduction of foundation

strength due to erosion, as recommended in the GALL Report.

(6) Erosion of porous concrete subfoundation

Section 3.5.2.2.2.1 of the SRP-LR refers to Section 3.5.2.2.1.2 for discussion of erosion of

porous concrete subfoundation. Section 3.5.2.2.1.2 of the SRP-LR states that reduction of

foundation strength due to erosion of porous concrete subfoundations could occur in all types of

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Class 1 structures. Some plants may rely on a dewatering system to lower the site ground

water level. If the plant's CLB credits a dewatering system, the GALL Report recommends

verification of the continued functionality of the dewatering system during the period of

extended operation. The GALL Report recommends no further evaluation if this activity is

included in the scope of the applicant's structures monitoring program.

Information Notice 97-11 does not identify ANO-2 as a plant susceptible to erosion of porous

concrete subfoundations. Ground water was not aggressive during plant construction, and;,

there is no indication that ground water chemistry has significantly changed. The applicant has

not observed any changes in ground water, conditions at ANO-2. Therefore, the staff finds that

cracking, distortion, and increase in the component stress level due to settlement and reduction

of foundation strength due to erosion of the porous concrete subfoundation are adequately

managed by the Structures Monitoring Program. ;

(7) Corrosion of structural steel components

Section 3.5.2.2.1 of the SRP-LR states that corrosion of structural steel components could

occur and that further evaluation is necessary only for structure/aging effect combinations not

covered by a structures monitoring program.-,,-

The staff reviewed the AMR results involving management of aging effects resulting from

corrosion of structural steel components and confirmed that the Structures Monitoring Program,

evaluated in Section 3.0.3.1 of this SER, addresses each of the affected SCs. On the basis of

this audit and review, the staff finds that the applicant has appropriately evaluated AMR results

involving this aging effect and that the Structures Monitoring Program adequately manages the

corrosion of structural steel components.

(8) Elevated temperatures -

Section 3.5.2.2.2.1 of the SRP-LR refers to Section 3.5.2.2.1.3 for discussion of elevated

temperatures. Section 3.5.2.2.1.3 of the SRP-LR states that reduction of strength and modulus

of elasticity due to elevated temperatures could occur in Class 1 structures in Groups 1-5. The

GALL Report calls for a plant-specific AMP and recommends further evaluation if any portion of

the concrete components exceeds specified temperature limits (i.e., general area temperature

66 IC (150 0F) and local area temperature 93 ?C (200 OF)).

The applicant stated in the LRA that, during normal operation, all concrete areas in Class 1

structures are below 66 0C (150 OF) ambient temperature. The applicant concluded that ANO-2

Class 1 concrete structures are not subject to change in material properties due to elevated

temperature.

The staff reviewed the AMR results involving management of aging effects resulting from

elevated temperature and confirmed that theStructures Monitoring Program, evaluated in

Section 3.0.3.1 of this SER, addresses each of the affected SCs. On the basis of this review,

the staff finds that the applicant has appropriately evaluated AMR results involving reduction of

strength and modulus due to elevated temperature, as recommended in the GALL Report, and

that it is adequately managed by the Structures Monitoring Program.

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(9) Aging effects for stainless steel liners for tanks

The applicant stated that the structural AMRs do not include tanks with stainless steel liners.

Instead, the applicant considered tanks subject to an AMR with their respective mechanical

systems. The staff confirmed that LRA Tables 3.5.2-1 through 3.5.2-4 do not include tanks with

stainless steel liners.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of aging of accessible interior and exterior concrete and steel

components of Class 1 structures (except Group 6 water-control structures), and all are

covered by the Structures Monitoring Program. This is consistent with the recommendations of

the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.2.2 Aging Management of Inaccessible Areas. In Section 3.5.2.2.2.2 of the LRA, the

applicant addressed aging of inaccessible areas of Class 1 structures.

Section 3.5.2.2.2.2 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability caused by aggressive chemical attack and cracking, spalling, loss of bond, and

loss of material due to corrosion of embedded steel could occur in belowgrade inaccessible

concrete areas. The GALL Report recommends further evaluation to manage these aging

effects in inaccessible areas of Group 1-3, 5, and 7-9 structures, if an aggressive belowgrade

environment exists. ISG-3 identifies additional requirements.

The GALL Report, as updated by ISG-3, states that aggressive chemical attack and corrosion

of embedded steel is not significant unless pH is less than 5.5, chlorides are greater than 500

ppm, or sulfates are greater thanl 500 ppm. In addition, ISG-3 states that a plant-specific

program is required to examine representative samples of belowgrade concrete when

excavated for any reason.

In the LRA, the applicant stated that the belowgrade environment is not aggressive (i.e.,

pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm). The

applicant used the Structures Monitoring Program, evaluated in Section 3.0.3.1 of this SER, to

examine belowgrade concrete when it is exposed by excavation. The applicant also stated that

inspections of accessible concrete have not revealed degradation due to aggressive chemical

attack or corrosion of embedded steel.

Because the belowgrade environment is not aggressive and the applicant will continue to

monitor excavated concrete, the staff finds that increases in porosity and permeability, loss of

material (e.g., spalling and scaling), and cracking due to aggressive chemical attack and

cracking, spalling, loss of bond, and loss of material caused by corrosion of embedded steel are

adequately managed for concrete in inaccessible areas.

3.5.2.2.3 Component Supports

The staff reviewed Section 3.5.2.2.3 of the LRA against the criteria in Section 3.5.2.2.3 of the

SRP-LR, which addresses several areas discussed below.

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3.5.2.2.3.1 Aping of SuDports Not Covered by Structures Monitoring Program. In Section

3.5.2.2.3.1 of the LRA, the applicant addressed aging of component supports that are not

managed by the Structures Monitoring Program...

Section 3.5.2.2.3.1 of the SRP-LR states that the GALL Report recommends further evaluation

of certain component support/aging effect combinations if they are not covered by a structures

monitoring program. This includes (1) reduction in concrete anchor capacity due to degradation

of the surrounding concrete for Group B1-B5 supports, (2) loss of material due to. :

environmental corrosion for Group B2-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 a structures monitoring

program.

The applicant's Structures Monitoring Program includes component supports at ANO-2,

evaluated in Section 3.0.3.1 of this SER, for Groups B2-B5. The Inservice Inspection Program

manages component supports in Group B1, evaluated in Section 3.0.3.4 of this SER.

(1) Reduction in concrete anchor capacity due to surrounding concrete for Group B1-B5

supports

The Structures Monitoring Program includes ANO-2 concrete anchors and surrounding

concrete (Groups B2-B5). The Inservice. Inspection Program includes these for Group B1.

(2) Loss of material due to environmental corrosion for Group B2-B5 supports

Loss of material due to corrosion of steel support components is an AERM at ANO-2. The

Structures Monitoring Program manages this aging effect.

(3) Reduction/loss of isolation function due to degradation of vibration isolation elements for

Group B4 supports

The LRA did not identify any vibration isolation elements subject to aging management.. -

The staff finds that the applicant has appropriately evaluated AMR results involving

management of aging of component supports, as recommended in the GALL Report. The staff

finds that the applicant has demonstrated that the effects of aging will be adequately managed

so that the intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21(a)(3). - -

3.5.2.2.3.2 Cumulative Fatigue Damage due to Cyclic Loading. As stated in the SRP-LR,

fatigue is a TLAA, as defined in 10 CFR 54.3. AII TLAAs must be evaluated in accordance with

10 CFR 54.21 (c)(1). Section 4.3 of this SER includes the staff's review of the applicant's

evaluation of this TLAA. In performing this review, the staff followed the guidance in Section

4.3 of the SRP-LR.

,. .

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3.5.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

Section 3.0.4 of this SER provides the staff's evaluation of the applicant's Quality Assurance

Program.

Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations,

conducted in accordance with the GALL Report, are consistent with the acceptance criteria in

Section 3.5.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3 AMR Results That Are Not Consistent with the GALL Report

3.5.2.3.1 Containment and Containment Internals

Summary of Technical Information in the Application

In Section 3.5.2.1.1 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the AERMs for the

containment and containment internals components:

* Boric Acid Corrosion Prevention Program

* Containment Leak Rate Program

* Inservice Inspection-Containment Inservice Inspection Program

* Inservice Inspection-Inservice Inspection Program

* Structures Monitoring Program

In Table 3.5.2-1 of the LRA, the applicant provided a summary of AMRs for the containment

and containment internals components and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation

Table 3.5.2-1 of the LRA indicates that the AMR results of the following items are consistent

with their corresponding GALL Report items for the component, material, environment, aging

effects, and AMPs:

* abovegrade concrete dome, wall, ring girder, and buttresses

* belowgrade concrete wall and buttresses

* concrete foundation

* concrete internal structures

* personal airlock and equipment hatch

In discussing LRA Table 3.5.1, Item 3.5.1-3, the applicant asserted that the ANO-2

Containment Inservice Inspection Program and Containment Leak Rate Testing program will

monitor loss of material due to corrosion of penetration bellows. Under Item A3.1 (page 11

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A3.6), the GALL Report recommends further evaluation regarding the SCC of contain-ment

bellows. The staff asked the applicant to provide additional information regarding the

containment pressure boundary bellows at ANO-2, relevant operating experience, and

method(s) used to detect their age-related degradation. The staff noted that, in many cases,

VT-3 examination of IWE and Type B (Appendix J) testing cannot detect such aging effects

(see NRC IN 92-20). -

In its response'dated May 19, 2004, the apoplicant stated that Item 3.5.1-3 pertains to'carbon

steel penetrations which'are not susceptible to'SCC.:- Consistent with the GALL Report, this

item does not require further evaluation; Item 3.5:1-2 addresses SCC of stainless steel

penetration bellows. No bellows are used for piping system containment penetrations; The fuel

transfer tube is equipped with bellows-type 'expansion'joints that con'nect'the transfer tube to

the liner of the refueling canal in containment and to the liner of the spent fuel pool in the

auxiliary building. Tables 2.3.3-1 and 3.3.2-1identify'the fuel transfer tube (assembly). Item

3.5.1-2 applies to the fuel transfer tube sleeve but not to the bellows, since the bellows is not

part of the containment penetration boundary.

Furthermore,' the applicant explained that the bellows connecting the transfer tube to the

refueling canal liner is an extension of the refueling canal liner,' which has no license renewal

intended function. The bellows on the other ehd of the transfer tube connects the transfer tube

to the liner in the fuel tilt pit portion of ,the spent fuel pool. The low point of the opening

connecting the spent fuel pool to the tilt pit is above the top of the spent fuel stored'in the

storage racks, so failure of the bellows cannot result in uncovering of the fuel. Therefore,

neither bellows attached to the fuel transfer tube performs a license renewal intended function.

Based on the response, the staff understands that'ANO-2 has no pressure-retaining bellows

(stainless steel or carbon steel) as part of the pressure-retaining containment penetrations.'

The staff finds the response acceptable, as it adequately justifies not explicitly considering the,

cracking of containment fuel transfer tube bellows as an aging management item during the

extended period of operation. However, as 'the fuel transfer tube' penetration (refer to Table

3.3.2-1) represents containment pressure boun'dary,'the applicant's Water Chemistry Control

Program and Containment Inservice Inspection Program will monitor its aging effects.

For seals and gaskets related to containment penetrations, the staff noted that LRA Table

3.5.1, Item 3.5.1-6, gives the Containment linsrvide Inspection Program and Containment Leak

Rate Testing Program as the'AMPs. 'For equipment hatches and airlocks at ANO'2, the staff

agreed with the applicant's assertion that the Leak'Rate Testing Program'would monitor aging

degradation of seals and gaskets, as their leak rate would be tested after each' ope'ning. For

other penetrations with seals and gaskets, in RAI 3.5-2, the staff asked the applicant to provide

information regarding the adequacy of Type B leak rate testing frequency to monitor aging

degradation of seals and gaskets at ANO-2.

In its response dated May 19, 2004, the ajpplicant stated that, for'ANO-2,'the equipm rent hatch

seal listed in Table 3.5.2-4 is the only line itemr for seals or gaskets that credits the Containment

Leak Rate Testing Pr6gramrri The equipment'hatch seal is the only line itern that refers to Item

3.5.1-6 of Table 3.5.1. -

The staff requested that the applicant provide information regarding the aging management of

seals and gaskets for mechanical and electrical penetrations''(other than those associated with

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equipment hatch and airlocks).

By letter dated July 22, 2004, the applicant provided the following additional information to

address RAI 3.5-2:

Gaskets associated with containment mechanical penetrations are consumables

that are replaced each time the bolted joint is disassembled. In addition, such

penetrations are tested under the containment leak rate program as required by

10 CFR 50, Appendix J. As indicated in LRA Table 3.5.2-1, containment

electrical penetrations (which include cable feed-through assemblies) are

included in the containment leak rate program. The effects of aging on seals

and gaskets associated with mechanical and electrical penetrations are

managed by the containment leak rate program. Line item 3.5.1-6 of Table 3.5.1

applies to seals and gaskets associated with mechanical penetrations and

electrical penetrations.

ANO-2 is committed to Option B of 10 CFR 50, Appendix J for performing

containment leakage rate testing. Option B allows Type B test intervals up to

120 months; however, normally it is performed more frequently than every 120

months. Type Btesting of ANO-2 mechanical and electrical penetrations is

performed at least once every 120 months. Component specific testing

frequency is based on the safety significance and historical performance of the

penetrations in accordance with Option B of 10 CFR 50, Appendix J.

The staff found the response acceptable, as it provides adequate details regarding the aging

management of pressure boundary seals and gaskets associated with containment electrical

and mechanical penetrations.

In its discussion of Item 3.5.12 in Section 3.5.2.2.1.4 of the LRA, the applicant noted that the

moisture barrier is monitored under the ASME Code, Subsection IWE, program for aging

degradation and, since the conditions described in the GALL Report are met for inaccessible

areas (i.e., liner plate), loss of material due to corrosion is insignificant. The industry

experience indicates that the moisture barrier degrades with time, and any moisture

accumulation in the degraded barrier corrodes the steel liner. The staff requested that the

applicant provide information regarding the operating experience related to the degradation of

the moisture barrier and the containment liner plate at ANO-2. The staff requested that the

applicant discuss acceptable liner plate corrosion before the liner plate would be reinstated to

its nominal thickness.

In response, the applicant stated the following:

The ANO-2 operating experience review did not identify degradation of the

moisture barrier and containment liner plate at ANO-2. The American Society of

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Xl,

Subsection IWE provides the requirements for ISI of containment structures.

The requirements include examination, evaluation, repair, and replacement of

the concrete containment liner plate in accordance with 1 OCFR50.55a. The

acceptable thickness for ANO-2 liner plate is determined in accordance with

ASME Boiler and Pressure Vessel Code, Section Xl, Subsection IWE.

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The staff noted that the applicant has not t

exp'erienced any degradation of the containment

moisture barrier and liner, and that the applicant'is -examining these components pursuant to

the requirements of Subsection IWE, as incorporated by reference in 10 CFR 50.55a. The staff

finds the condition acceptable, as it provides an assurance that these components will be

adequately managed for aging effects during the extended period of operation.

For structural items inside-the ANO-2 contaimriri6t (e.g., primary and secondary shield walls,

reactor missile shields, and RV foundation), in Table 3.5.2 of the LRA, 'the applicant ref erred to

Notes land 501 to indicate that the'ten,6ira-ttures'around these comriporients are'within the

GALL Report threshold, and, therefore, the aging effects (i.e., reduction in concrete strength

and modulus of elasticity) do not apply (also discussed, in general, in Section 3.5.2.2.1.3 of the

LRA). In this context, in RAI 3.5-4(a), (b) and (c), the staff asked the applicant to provide the

following information.

(a) Provide the method(s) of monitoring temperatures within the primary shield wall

concrete, around the reactor vessel, and in the reactor cavity.

In response, the applicant stated the following:

Temperatures within the primary 'hield wall concrete are not directly monitored.'

Assurance that bulk concrete temperatures around the reactor vessel within the

reactor cavity remain below 150 'F is obtained through maintaining average bulk

containment temperature within the limits allowed by ANO-2 Technical

Specification 3.6.1.4. Since forced cooling is provided directly to the reactor:

cavity, its temperature is lower than the bulk average containment temperature.'

A review of containment temperatU'e readings from near the reactor vessel over

the last 12 months, as recorded in' the plant data system, show the area

temperature has remained below 150 OF.

Based on the above assurances, the staff believes'that the concrete properties will not be

significantly changed as a result of these temperatures.

(b) If the primary shield wall concrete is kept below the threshold temperature (i.e., 150 OF)

by means of air cooling, provide the operating experience related to the performance of

the cooling system.

In response, the applicant stated the following:

The primary shield wall concrete temperature is kept below the threshold

temperature by means of air cooling. "The opeiating experience'review did not

identify significant degradation or system failures. The technical specification

requirement on containment temperature provides assurance that plant

operation will continue only with satisfactory performance' of the containment

cooling system. --

Based on the assurances provided in response to (a) and (b) above, the staff believes that the

concrete properties around the primary shield wall and RPV support structure will not be

significantly changed as a result of these temperatures.

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(c) Provide the results of the latest inspection of these components, in terms of cracking,

spalling, and the condition of reactor vessel support structures.

In response, the applicant stated the following:

The results of the last inspection of the reactor vessel supports, performed

during the spring 1997 refueling outage, identified inactive boron deposits on the

support steel. The condition was evaluated under the Boric Acid Corrosion

Program and determined to have no effect on the support's ability to perform its

intended function. No other conditions were identified.

The Boric Acid Corrosion Program only addresses the conditions affected by boric acid

exposure. It cannot, by itself, indicate the condition of the concrete structures. Section X.S6 of

the GALL Report recommends the use of ACI 349-3R, as part of the Structures Monitoring

Program (as summarized in ANO-2 AMP B.1.27), for identifying and evaluating degradation of

concrete structures, including the structures inside containment. Therefore, the staff asked the

applicant to provide the information requested in RAI 3.5-4(c) in terms of the criteria established

in Chapter 5 of ACI 349-3R.

By letter dated July 22, 2004, the applicant provided the following information to address RAI

3.5-4(c):

The Structures Monitoring Program is used for evaluation of concrete structures.

The evaluation criteria in ACI 349-3R are incorporated in the Structures

Monitoring Program. The Structures Monitoring Program provides the same

criteria for identifying concrete degradation as ACI-349-3R. During the latest

inspection, the concrete of the primary shield wall and the reactor pressure

vessel support structure was acceptable without further evaluation in accordance

with the criteria of ACI 349-3R, Section 5.1. No cracking or spalling of the

primary shield wall or reactor pressure vessel support concrete structures was

noted during the inspection.

The staff finds the response acceptable, as the criteria used in Structures Monitoring Program

will adequately manage the aging of concrete structures subjected to elevated temperatures.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) can be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

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3.5.2.3.2 Auxiliary Building, Turbine Building, and Yard Structures

Summary of Technical Information in the Application

In Section 3.5.2.1.2 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the AERMs forithe

auxiliary building, turbine building, and yard structures components:

* Structures Monitoring-Masonry Walls Program (Appendix B.1.26) -

* Structures Monitoring Program (Appendix B.1.27)

* Water Chemistry Control Program (Appendix B.1.30)

In Table 3.5.2-2 of the LRA, the applicant provided a summary of AMRs for the auxiliary

building, turbine building, and yard structures components and identified which AMRs it

considered to be consistent with the GALL Report.

Staff Evaluation

The applicant used the Structures Monitoring-Masonry Wall Program as the AMP for seismic

Category I masonry block walls, the Structures Monitoring Program for concrete material (such

as building walls, slabs, beams, columns, and foundations) and carbon steel material (such as

fuel handling bridge assembly crane rails and girders, high-energy line break doors, and

switchyard bus and transformer bus structural supports), and the Water Chemistry Control.

Program for stainless steel material (such as spent fuel pool liner and bulkhead gates). -

On the basis of its review of the LRA, the staff finds that the aging effects on the structural

components of the auxiliary building, turbine building, and yard structure with the environments

described in Table 3.5.2-2 of the LRA are consistent with industry experience for these

combinations of materials and environments. Therefore, the staff finds that the applicant

identified the applicable aging effects and associated AMPs that are appropriate for the

combinations of materials and environments listed.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) can be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21(a)(3)._

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.3 Intake Structure and Emergency Cooling Pond

Summary of Technical Information in the ADplication

In Section 3.5.2.1.3 of the LRA, the applicant noted that the intake structure and emergency

cooling pond (constructed from materials of carbon steel, natural soils, and reinforced concrete

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and subject to environments of raw water, weather, and protected weather conditions) require

management of aging effects of loss of form and loss of material. The applicant credited the

following programs to manage the aging effects:

* Service Water Integrity Program (Appendix B.1.24)

* Structural Monitoring Program (Appendix B.1.27)

* Periodic Surveillance and Preventive Maintenance Program (Appendix B.1.18)

In Table 3.5.2-3 of the LRA, the applicant provided a summary of AMRs for the intake structure

and emergency cooling pond and identified which AMRs it considered not to be consistent with

the GALL Report.

Staff Evaluation

The applicant used the Service Water Integrity Program as the AMP for submerged pump and

shaft supports (made of carbon steel) and the emergency cooling pond concrete intake (made

of reinforced concrete), the Structures Monitoring Program for concrete material (such as

building walls, floor slabs, roof slabs, beams, columns, and foundations) and carbon steel

material (such as floor hatches, louvered doors, and beams in service water and circulating

water bays), and the Periodic Surveillance and Preventive Maintenance Program for the

emergency cooling pond (made of natural soils).

Table 3.5-2-3 indicates that the applicant provided no AMP for the intake canal. The staff

issued RAI 3.5-9, which states that the intended function of the intake canal, as listed on Table

3.5.2-3, is to provide structural or functional support to equipment required to meet the

Commission's regulations for the five regulated events in 10 CFR 54.4(a)(3). Section 2.4.3 of

the LRA states that the intake canal provides a suction source for the fire water and service

water pumps. However, the applicant provided no AMP for the intake canal. Therefore, the

staff requested that the applicant justify not providing an AMP for the intake canal and explain

how the intended function can be met without an AMP.

In its response dated May 19, 2004, the applicant stated the following:

The intended function of the intake canal can be met without an aging

management program because the canal has no aging effects requiring

management. As described in ANO-2 SAR Section 2.5.5.1, the seismic stability

of the intake canal slope was analyzed. The intake canal is qualified as Seismic

Category 1. The intake canal has adequate vegetation and consists of

engineered slopes to limit erosion caused by wind. The intake canal was

completely excavated and contains no sections formed by dikes or fill. The

overburden soils at the site are mainly stiff highly plastic clays. At the intake

canal about 13 to 25 feet of clay overlies weathered bedrock. The underlying

bedrock consists of dense shale with about two to five feet of weathered shale

which prevents erosion of the bed. In addition, since the intake canal was

designed with the capacity to supply circulating water to ANO-1, its capacity is

far greater than required to provide service water to ANO-2. As a result no aging

effects requiring management are identified in Table 3.5.2-3. This is consistent

with a previously approved staff position documented in Section 3.3.6.6.2.1 of

NUREG-1743, Safety Evaluation Report Related to the License Renewal of

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Arkansas Nuclear One-Unit 2. :

The staff disagrees with the applicant's assertion that the canal has no AERMs. The applicant's

statement that the intake canal is qualified as seismic Category 1 further demonstrates the

need for an AMP.

In its response, dated August 18, 2004, the applicant committed to inspect the intake canal

periodically as part of the ANO Maintenance Rule program during the period of extended

operation. This commitment is acceptable to the staff.

On the basis of its review of the LRA, the staff finds that the aging effects on the structural

components of the intake structure, intake canal, and emergency cooling pond with the

environments described in Table 3.5.2-3 of the LRA are consistent with industry experience for

these combinations of materials and environments. Therefore, the staff finds that applicant

identified the applicable aging effects and associated AMPs that are appropriate for the

combinations of materials and environments.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) can be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21(a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.4 Bulk Commodities

Summary of Technical Information in the Application

In Section 3.5.2.1.4 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following-programs that manage the AERMs for the bulk

commodities components:

Fire Protection Program (Appendix B.1.10)

* Inservice Inspection-Inservice Inspection Program (Appendix B.1.14)

* Structures Monitoring Program (Appendix B.1.27)

* Containment Leak Rate Testing Program (Appendix BA1.6)

In Table 3.5.2-4 of the LRA, the applicant provided a summary of AMRs for the bulk

commodities components and identified which AMRs it considered to be consistent with the

GALL Report. ; ..

Staff Evaluation i} V: In i--

The applicant used the Fire Protection Program as the AMP for fire doors and fire hose reels

(carbon steel), fireproofing (pyrocrete material), and fire barrier seals (elastomers material); the

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Inservice Inspection (IWF) Program for base plates, component supports (e.g., instrument

racks and frames), main steamline support structure, piping supports, anchor bolts, and RCS

component support threaded fasteners (for the steam generator, RCP, pressurizer) which are

made of carbon steel; the Structures Monitoring Program for cable tray and conduit supports,

embedded unistrut, electrical instrument panels and enclosures, fir damper framing, HVAC

missile barrier, monorails, crane rails and girders, pipe sleeves (mechanical/electrical, not

penetrating the containment liner plate), pipe whip restraints, stairs, ladders, platforms, grating,

anchor bolts in switchyard structures, tank anchors, threaded fasteners, equipment pads, flood

curbs, hatch covers and plugs, missile shields, support pedestals, joint elastomers at seismic

gaps, and penetration seals; and the Containment Leak Rate Testing Program for equipment

hatch seals.

On the basis of its review of the LRA, the staff finds that the aging effects on the structural

components of the bulk commodities with the environments described in Table 3.5.2-4 of the

LRA are consistent with industry experience for these combinations of materials and

environments. Therefore, the staff finds that the applicant identified the applicable aging effects

and associated AMPs that are appropriate for the combinations of materials and environments

listed.

The staff issued RAI 3.5-5, dated May 19, 2004, given below:

LRA Section 3.5.2.2.1.1 states that the, below-grade environment is not

aggressive (pH > 5.5, chlorides < 500 ppm, and sulfates < 1,500 ppm). The

applicant is requested to provide the values of pH, chlorides, and sulfates at the

plant site and when they were obtained. In IlIl A7.1 -e, GALL recommends

periodic monitoring of below-grade water chemistry for non-aggressive

environments. Since the applicant has made no commitment to periodically

monitor the groundwater, the applicant is requested to submit its method for

assuring the continuing verification of the non-aggressiveness of the

below-grade environment.

The applicant provided the following response:

The most recent data associated with ANO groundwater chemistry was obtained

in May 1996. The results of this analysis are as follows (values obtained near

ANO-2 containment):

pH = 7.23

chlorides < 5 ppm

sulfates = 20.3 ppm

Comparing this data to that of the ANO-2 SAR Table 2.4-4 (well point 1) and

Figure 2.4-1 (well point location), the limiting chemistry parameters have shown

no significant increase and are still far from the established limits. The existing

data indicates that there has been no significant change in groundwater

chemistry since original licensing (a period of approximately 25 years) that would

warrant increased monitoring and it is not anticipated to significantly change in

the future. Therefore, periodic monitoring of groundwater chemistry is not

required to assure the non-aggressiveness of the below-grade environment.

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I
The staff disagrees with the applicant's assertion that periodic monitoring of ground water

chemistry is not required to assure the non-aggressiveness of the below-grade environment.

Even though ground water chemistry has not changed significantly in the past, the ground water

chemistry is not guaranteed to remain the same in the future. Therefore, periodic monitoring of

ground water chemistry in the future is'needed to assure that ground water chemistry does not

change significantly.

The applicant submitted its response, dated August 18, 2004:

Wells are no longer available for sampling groundwater. Consequently, in lieu of

sampling groundwater to confirm that it remains non-aggressive, concrete

exposed to groundwater is included in the Structures Monitoring Program for

inspection to confirm the absence of aging effects. Under the Structures

Monitoring Program, concrete exposed to lake water is periodically inspected.

Since lake water chemistry is representative of groundwater chemistry, results of

these inspections will be representative of underground concrete exposed to

groundwater. In addition, when excavated for maintenance activities, ' inaccessible concrete exposed to groundwater will be visually inspected under

the Structures Monitoring Program.,

The applicant's Structures Monitoring program uses inspections of the service water bays as a

surrogate for inaccessible concrete exposed to groundwater. At least one service water bay is

usually inspected during each outage. The Structures Monitoring program uses these

inspections in conjunction with opportunistic inspections to manage the aging effects of

inaccessible concrete exposed to groundwater. The staff accepts the applicant's use of the

Structures Monitoring Program as an AMP to-confirm the absence of concrete aging effects

due to ground water.

The staff's RAI 3.5-6, dated May 19, 2004, is given below:

Item 3.5.1-22 of Table 3.5.1 indicates that the applicant intends to use the

Structures Monitoring Program to manage the aging effect for Group 6

structures instead of using the Generic Aging Lessons Learned (GALL) Chapter

XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers

dam inspections and maintenance.: The applicant is requested to list the

attributes, which are in the GALL but not in the ANO-2 Structures Monitoring

Program, and provide justifications for use of the Structures Monitoring Program

without those attributes. :

In its response dated May 19, 2004, the applicant stated the following:

Regulatory Guide (RG) 1.127, Inspection of Water-Control Structures associated ... 41, ^g.-1- ED.., 01--; f- +:~f VI Or ,-; AI I Do - __
operating experience.

The attributes that are in the GALL XI.S7 aging management program, but not

in the ANO-2 Structures Monitoring Program, are attributes dealing with earthen

embankment water control structures. RG 1.127 proposes inspection

parameters (e.g., settlement, depressions, sink holes, slope stability (e.g.,

irregularities in alignment and variances from originally constructed slopes),

seepage, proper functioning of drainage systems, and degradation of slope

protection features) and frequency (not to exceed 5 years) for earthen

embankment water control structures. During the ANO-2 aging management

review, the only aging effect requiring management for earthen structures was

determined to be loss of form of the emergency cooling pond. Loss of form is

effectively managed by sounding under the Periodic Surveillance and Preventive

Maintenance Program as indicated in LRA Table 3.5.2-3. Therefore, the

attributes of the NUREG-1801 XI.S7 aging management program regarding

earthen structures are not necessary attributes for the ANO-2 Structures

Monitoring Program for water control structures.

The applicant noted that the loss of form of the emergency cooling pond is the only aging effect

that requires an AMP for earthen structures. The staff believes that the intake canal is an

earthen water-control structure at ANO-2, which also requires an AMP.

The applicant submitted its response, dated July 22, 2004, and clarified. that water-control

structures at ANO-2 also include the intake canal. The applicant committed to inspect the

intake canal periodically as part of the ANO Maintenance Rule program during the period of

extended operation, as documented in Section 3.5.2.3 of this SER.

Since the intake canal is included in the water-control structures and will be periodically

inspected, the staff considers the RAI resolved.

The staff's RAI 3.5-7, dated May 19, 2004, is given below:

Item 3.5.1-23 of Table 3.5.1 indicates that the applicant does not plan to monitor

the spent fuel pool water level as stated in the GALL in managing liners for crack

initiation and growth due to SCC; loss of material due to crevice corrosion. The

applicant is requested to provide justifications for the exclusion of this GALL

aging management program.

In its response dated May 19, 2004, the applicant stated the following:

Monitoring of spent fuel pool level is required by ANO-2 Technical Specification

4.9.10. This activity was not crediting an aging management program because

of its very limited scope. As stated in the LRA, the ANO-2 Water Chemistry

Program provides effective management of the effects of aging on the spent fuel

pool liner.

The staff was unclear about the applicant's statement that monitoring of spent fuel pool level,

'was not crediting an aging management program because of its very limited scope." And

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requested the applicant to explain what was meant by the "very limited scope" and why the

monitoring of spent fuel pool water level can not be credited as an AMP.

The applicant submitted its response, dated July 22, 2004, given below:

The response should have said, 'This activity was not credited as an aging

management program because of its very limited scope." This was intended to

reflect the treatment of spent fuel pool level monitoring in NUREG-1 801, which

identifies spent fuel pool level monitoring 'in the aging management program

column in Item A5.2 but does not include it in the program descriptions of -:

Section XI of NUREG-1 801. Spent fuel pool level monitoring is credited to verify

effectiveness of the water chemistry control program to manage the effects of

aging on the spent fuel pool liner. At ANO-2 this activity is performed as

required by ANO-2 Technical Specification 4.9.10.

Since the applicant has credited the spent fuel pool water level monitoring activity for managing

the effects of aging on the spent fuel pool liner, the staff considers the RAI resolved.

The staff's RAI 3.5-8, dated May 19, 2004, is given below:

Item 3.5.1-33 of Table 3.5.1 indicates that the applicant intends to use inservice

inspection (IWF) and Boric Acid Corrosion Prevention Programs to manage the'

crack initiation and growth due to SCC for high strength low-alloy bolts instead of

using the GALL Bolting Integrity Program' The applicant is requested to identify

bolts that have actual yield strength equal to or greater than 150 ksi and provide

justification for not using the Bolting Integrity Program.

In its response dated May 19, 2004, the applicant stated the following:

A more appropriate statement for "Discussion".column for item 3.5.1-33 is "This

is not an applicable aging effect for.ANO-2 structural bolts. 'This line item is not

referenced in the 3.5.2-series table.".;:;-

The materials used in bolting and threaded structural steel connections within the

scope of license renewal are identified in ANO-2 SAR Section 3.8.3.6.2.2.; -;

ANO-2 utilizes a limited number of high strength bolts (yield strength >150 ksi) in

structural connections. The ANO-2 aging management review identifies loss of

material (but not cracking) as the aging effect requiring management for these

bolts. Cracking of bolting in an air environment due to SCC has not been

observed at ANO-2 and was not identified in a survey of industry experience.

For ANO-2 the Inservice Inspection (IWF) and Boric Acid Corrosion Prevention

Programs are credited and have been determined to be effective in managing

loss of material.

The staff did not understand the applicant's statement that: 'This is not an applicable aging

effect for ANO-2 structural bolts," since the applicant stated that a limited number of highstrength bolts (i.e., yield strength greater than 150 ksi) were used in structural connections.

The staff requested the applicant to provide technical bases for its AMR conclusion that the

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SCC is not an aging effect for these high-strength bolts, as well as references to the claim that

cracking of bolting in an air environment due to SCC has not been observed in a survey of

industry experience.

The applicant submitted its response, dated July 22, 2004, as given below:

The high strength bolts refe rred to in the response to RAI 3.5-8 are identified in

ANO-2 SAR Section 3.8.3.6.2.2. A more detailed review revealed that these

bolts have a yield strength less than 150 Ws. No high strength bolts having a

yield strength greater than 150 ksi were used in structural connections at ANO-2.

This was confirmed through review of a number of material test reports for

ANO-2 high strength bolts.

Since ANO-2 does not contain any bolts having a yield strength greater than 150 ksi, the staff

considers the RAI resolved.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended functions) can be maintained

consistent with the current licensing basis for the period of extended operation, as required by

1 0 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 1 0 CFR 54.21 (d).

3.5.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the containments, structures, and component supports 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 1 0 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

containments, structures, and component supports, as required by 1 0 CFR 54.21 (d).

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3.6 Electrical and Instrumentation and Controls

- I-..

The applicant described the results of its AMR for electrical and instrumentation and control

components subject to an AMR in Section 3.6 of the LRA. The staff reviewed this section of the

application to determine whether the applicant has demonstrated that the effect of aging on

electric components will be adequately managed during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.6.1 Summary of Technical Information In the Application

In Section 3.6 of the LRA, the applicant provided the results of the AMR of the electrical and

l&C components listed in Table 2.5-1 of the LRA., The applicant also listed the materials,

environments, AERMs, and AMPs associated with each commodity group.

In Table 3.6.1 of the LRA, the applicant provided a summary comparison of its AMRs with the

AMRs evaluated in the GALL Report for the electrical and l&C components and component

types. In Section 3.6.2.2 of the LRA, the applicant provided information concerning Table 3.6.1

components for which the GALL Report recommends further evaluation.

The applicant addressed the following electrical components as commodity groups requiring an

AMR:

* insulated cables and connections

* phase bus . .:

* switchyard bus . ' - - -

* high-voltage insulators - .;

The following summarizes the materials, environments, aging effects requiring management,

AMPs, and further evaluations of aging management recommended by the GALL Report.

Table 3.6.2-1, "Electrical and l&C Components - Summary of Aging Management Evaluation,":

of the LRA further summarizes the results of the applicant's AMR and provides the NUREG1801, "Generic Aging Lessons Learned (GALL) Report," comparison for electric components.

* -Materials from which electrical components subject to an AMR are constructed include

the following: - -.-

* - aluminum !';

- cement

- copper and copper alloys

porcelain

steel

- .. . organic polymers - - galvanized metals - -:i-.

* Environments to which electrical components subject to an AMR are exposed include

* the following: i F '

. ... l a. k a '!' .

- borated water leakage

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- heat and air

- moisture and voltage stress

- radiation and air

- outdoor weather

* Aging effects associated with electrical components requiring management include the

following:

- loss of circuit continuity

- reduced insulation resistance

* AMPs for managing the effects of aging on electrical components include the following:

- Boric Acid Corrosion Prevention Program

- Non-EQ Inaccessible Medium-Voltage Cable Program

- Non-EQ Insulated Cables and Connections Program

* The GALL Report recommends further evaluation of aging management for the

following:

- electrical equipment subject to environmental qualification

- quality assurance for aging management of nonsafety-related components

Appendix B to the LRA describes the AMPs and demonstrates that the identified aging effects

will be managed for the period of extended operation. Based on these demonstrations, the

applicant concluded that the effects of aging associated with electrical components will be

managed such that there is reasonable assurance the intended functions will be maintained

consistent with the CLB during the period of extended operation.

3.6.2 Staff Evaluation

In Section 3.6 of the LRA, the applicant describes its AMR for electric components at ANO-2.

The staff reviewed Section 3.6 to determine whether the applicant has provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

intended functions of electric components will be maintained consistent with the CLB

throughout the period of extended operation, in accordance with the requirement of 10 CFR

54.21 (a)(3).

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of electric components for license renewal as documented

in GALL Report. Thus, the staff did not repeat its review of the matters described in the GALL

Report, except to ensure that the material presented in the LRA was applicable, and to verify

that the applicant had identified the appropriate programs as described and evaluated in the

GALL Report. The staff also reviewed aging management information submitted by the

applicant that was different from that in the GALL Report or was not addressed in the GALL

Report. Finally, the staff reviewed the proposed FSAR supplement to ensure that it provided an

adequate description of the programs credited with managing aging for electric components.

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The staff performed an audit to confirm the applicant's claim that certain identified AMPs are

consistent with the staff-approved AMPs in 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 applies and that the applicant had identified the appropriate GALL AMRs.

Section 3.5.2.1 of this SER summarizes the staff's audit findings.

The staff also audited those items that are consistent with the GALL Report and for which

further evaluation is recommended. The staff determined that the applicant performed its

further evaluations consistent with the acceptance criteria in Section 3.6.3.2 of the SRP-LR.

Section 3.6.2.2 of this SER summarizes the staff's audit findings.

The staff conducted a technical review of the remaining items that were not consistent with the

GALL Report. The review included evaluating whether the applicant identified all plausible

aging effects and listed the appropriate aging effects for the combinations of materials and :

environments specified. Section 3.6.2.3 of this SER documents the staff's review findings.

Finally, the staff reviewed the proposed FSAR Supplement to ensure that it adequately

describes the programs credited with managing aging for electrical components.

Table 3.6-1 below provides a summary of the staff's evaluation of components, aging -

effects/mechanisms, and AMPs listed inLRA Section 3.6 that are addressed in the GALL:-

Report.

Table 3.6-1 Staff Evaluation Table for ANO-2 Electrical Component Evaluations inr the

GALL Report

:SAComponent MP:n ALins LA Staff Evalualton.

;Gro "' EffecMlechaim I t.Rort : ht -t 

Electrical Degradation due to Environmental Environmental TLAA, See Section 4.4 of the

equipment subject various aging Qualification of Qualification of SER

to 10 CFR 50.49 mechanisms Electrical Electrical

EQ requirements Components Components

(Item Number (B.1.8)

3.6.1-1)

Electrical cables Embrittlement, Electrical cables and Non-EQ Insulated Consistent with GALL, which

and connections cracking, melting, connections not Cables and recommends no further

not subject to' discoloration, swelling, subject to Connections' evaluation (See Section .3)

10 CFR 50.49 EQ or loss of dielectric CFR 50.49 EQ (B.1.16)

requirements strength leading to requirements -:

(Item Number reduced insulation

3.6.1-2) resistance (IR);

electrical failure,

caused by thermal/

thermoxidative

degradation of

organic; radiolysis and

photolysis (ultraviolet

[UVj sensitive

materials only) of

organic; radiationinduced oxidation;

moisture intrusion

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-Grup-, i.'Efect/echahs At. J:^ -;,lex!n eElectrical cables Embrittlement, AMP for electrical Environmental Non-GALL Program (See

used in cracking, melting, cables used in Qualification of Section 3.6.2.1.4) instrumentation discoloration, swelling, instrumentation Electrical

circuits not subject or loss of dielectric circuits not subject to Components

to 10 CFR 50.49 strength leading to 10 CFR 50.49 EQ (B.1.8)

EQ requirement reduced IR; electrical requirements

that are sensitive failure caused by

to reduction in thermal/thermconductor oxidative degradation

resistance (Item of organic; radiationNumber 3.6.1-3) induced oxidation;

moisture intrusion

Inaccessible Formation of water AMP for inaccessible Non-EQ Insulated Consistent with GALL, which

medium-voltage (2 trees, localized medium-voltage Cables and recommends no further

kV to 15 kV) damage leading to cables not subject to Connections evaluation (See Section

cables (e.g., electrical failure 10 CFR 50.49 EQ (B.1.15) 3.6.2.1.2)

installed in conduit (breakdown of requirements

or direct buried) insulation); water

not subject to 10 trees caused by

CFR 50.49 EQ moisture intrusion

requirements

(Item Number

3.6.1-4)

Electrical Corrosion of Boric Acid Corrosion Boric Acid Consistent with GALL, which

connectors not connector contact Corrosion (B.1.3) recommends no further

subject to 10 CFR surfaces caused by evaluation (See Section

50.49 intrusion of borated 3.0.3.2.1)

requirements that water

are exposed to

borated water

leakage (Item

Number 3.6.1-5)

The staff's review of the ANO-2 electrical and instrumentation and controls system and

associated components followed one of several approaches. One approach, documented in

Section 3.6.2.1 of this SER, involves the staff's audit and review of the AMR results for

components in the electrical and instrumentation and controls system that the applicant

indicated are consistent with the GALL Report and do not require further evaluation. Another

approach, documented in Section 3.6.2.2 of this SER, involves the staff's review of the AMR

results for components in the electrical and instrumentation and controls system that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in Section 3.6.2.3 of this SER, involves the

staff's technical review of the AMR results for components in the electrical and instrumentation

and controls system that the applicant indicated are not consistent with the GALL Report, or are

not addressed in the GALL Report. AMPs that are credited to manage or monitor aging effects

of the electrical and instrumentation and controls system components are reviewed in Sections

3.0.3.1 and 3.6.2.1 of this SER.

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3.6.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the ADplication

In Section 3.6.2.1 of the LRA, the applicant identified the materials, environments, and AERMs.

The applicant identified the following programs that manage the aging effects related to the

electrical and l&C components:

* Boric Acid Corrosion Prevention Program

* Non-EQ Inaccessible Medium-Voltage Cable Program

* 'Non-EQ Insulated Cables and Connections Program

Staff Evaluation

In Table 3.6.2-1 of the LRA, the applicant provided a summary of AMRs for the electrical and

I&C components and identified which AMRs it considered to be consistent with the GALL -'

Report. 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 indicat6ethat the AMR was consistent with the GALL

Report.

Note A indicates that the AMR line item is consistent with the GALL Report for the 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 the 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 confirmed that it had reviewed and accepted the identified

exceptions to the GALL AMPs. 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 is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item is different from, but consistent with,

the GALL Report for the 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'

could not find a listing of some system components in the GALL Report.I 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 applies to the component under review

and whether the AMR is valid for the site-specific conditions. ' -

Note D indicates that the component for the AMR line item is different from, but consistent with,

the GALL Report for the 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 determined whether the AMR line item of

the different component applies to the component under review. The staff determined that it

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had reviewed and accepted the identified exceptions to the GALL AMPs. 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 is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for the 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 by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the LRA and program basis documents, which are

available at the applicant's engineering office. The results of the audit and review are

documented in the ANO-2 Audit and Review Report. On the basis of its audit and review, the

staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are consistent with the AMR results in the GALL Report. Therefore, the staff finds that

the applicant identified the applicable aging effects that are appropriate for the combinations of

materials and environments listed.

Staff Evaluations Pertaining to Recent Operating Experience and Emerging Issues

Because the GALL Report and SRP-LR were issued in July 2001, these documents do not

reflect the most current recommendations for managing certain aging effects that have been

the subject of recent operating experience or the topic of an emerging issue. As a result, the

staff reviewed the following AMR to determine how the applicant proposed to address these

items for license renewal. The staff's evaluations are documented as follows.

3.6.2.1.1 AMR for Electric Connectors not Subject to 10 CFR 50.49 Requirements that are

Exposed to Borated Water Leakage

Summary of Technical Information in the Application

The applicant stated in Table 3.6.2-1, "Electrical Components - Summary of Aging

Management Evaluation," of the LRA that electric connections exposed to borated water

leakage subject to an AMR (a) are constructed of various metals, (b) are exposed to borated

water leakage, (c) performs the function of providing electrical connections to specified sections

of an electrical circuit to deliver voltage and current or signals, (d) are subject to the aging effect

of loss of circuit continuity, and (e) require aging management. The aging effect of loss of

circuit continuity (caused by the environment consisting of borated water leakage) was

identified as causing loss of capability of providing electrical connections to specified sections of

an electrical circuit to deliver voltage, current or signals. The applicant concluded that an

environment consisting of exposure to borated water leakage will have the aging effect over

time of causing loss of circuit continuity through the various metals from which connections are

constructed; therefore, an AMP is required.

Staff Evaluation

The staff agrees that an environment consisting of borated water will have a significant aging

effect on various metals (the component parts from which connections are constructed);

therefore, an AMP for boric acid corrosion prevention is required. The staff's evaluation of the

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AMP for boric acid corrosion prevention is addressed in Section 3.0.3.2.1 of this SER. On the

basis of its review, the staff ther6fore concludes that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).'

Aging Management Programs

In Section 3.6.2.1 of the LRA, the applicant identified the materials, environments, and aging,

effects requiring management. The applicant identified the following programs that manage the

aging effects requiring management for the electrical and l&C components:

* - Boric Acid Corrosion Prevention Program (Appendix B.1.3)

* Non-EQ Inaccessible Medium-Voltage Cable (Appendix B.1.15)

* Non-EQ Insulated Cables and Connectors (Appendix B.1.16)

The staff's evaluation of the AMP for Boric Acid Corrosion Program is addressed'in Section

3.0.3.2.1 of this SER. The staff's evaluation for the Non-EQ Inaccessible Medium-Voltage

Cable Program and Non-EQ Insulated Cables and Connectors are included in this section of

the SER. The applicant also identified the AMP for Environmental Qualification of Electrical

Components (B.1.8) as the program to manage electrical cables used in instrumentation

circuits not subject to 10 CFR 50.49 requirements that are sensitive to reduction in conductor

resistance: This evaluation is contained in this section of the SER.- The staff evaluated the -

AMPs to determine if they are appropriate for managing the identified aging effects. The staff

also verified that the UFSAR Supplement adequately describes the program.

3.6.2.1.2 AMP for Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 EQ''

- Requirements

The Non-EQ Inaccessible Medium-Voltage Cables Program is described in Section B.1.1 5 of

the LRA. The LRA credits this Program with assuring that the intended functions of

inaccessible medium-voltage cables exposed to the-aging effects of moisture and voltage

stress will be maintained consistent'with -the'CLB through the period of extended operation. -

The staff reviewed the LRA to determine whether the applicant has demonstrated that the Non-:

EQ Inaccessible Medium-Voltage Cables Program will adequately manage the applicable aging

effects throughout the period of extended bperation; as required by 10 CFR 54.21 (a)(3).

Summary of Technical Information in the Application

The applicant's Non-EQ Inaccessible Medium-Voltage Cables Program is discussed in LRA

Section B.1.15, "Non-EQ Inaccessible Medium-Voltage Cable." The applicant states that their

program will be consistent with the program described in the GALL Report, Section XL.E3,

"Inaccessible Medium-Voltage Cables not Subject to 1 OCFR50.49 Environmental Qualification

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Requirements." In this aging management program, the applicant indicates that periodic

actions will be taken to prevent cables from being exposed to significant moisture, such as.

inspecting for water collection in cable manholes and conduit, and draining water, as needed.

In-scope medium-voltage cables exposed to significant moisture and voltage will be tested to

provide an indication of the condition of the conductor insulation. The specific type of test

performed will be determined prior to the initial test.

The applicant describes the program as a new program that will be effective for managing

aging effects since it will incorporate appropriate monitoring techniques. The Non-EQ

Inaccessible Medium-Voltage Cable Program will provide 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. The program will be initiated prior to the period of extended operation.

The applicant's proposed FSAR supplement for the Non-EQ Inaccessible Medium-Voltage

Cables Program is discussed in LRA Section A.2.1.16. The applicant states that this program

will apply to inaccessible (e.g., in conduit or direct buried) medium-voltage cables within the

scope of license renewal that are exposed to significant moisture simultaneously with applied

voltage. In this aging management program, periodic actions will be taken to prevent cables

from being exposed to significant moisture. In-scope medium-voltage cables exposed to

significant moisture and voltage will be tested to provide an indication of the condition of the

conductor insulation. The specific type of test performed will be determined prior to the initial

test. The Non-EQ Inaccessible Medium-voltage Cable Program will be initiated prior to the

period of extended operation.

Staff Evaluation

In LRA Section 6.1.15, uNon-EQ Inaccessible Medium-Voltage Cable," the applicant discusses

its proposed program for managing the aging effects from moisture and voltage stress. The

LRA states that this program will be consistent with the GALL Report Section XL.E3 and will be

initiated prior to the period of extended operation.

Based on the applicant's statement that their proposed program for managing the effects of

aging will be consistent with the GALL Report Section XL.E1, the staff concludes, pursuant with

the GALL Report guidelines, that no further evaluation is needed. The applicant has, therefore,

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). On the basis of its review, the staff finds that the AMP

credited in the LRA for the inaccessible medium-voltage cables not subject to 10 CFR 50.49 EQ

requirements will effectively manage or monitor the aging effects identified in the LRA.

Section A.2.1.16 of the LRA contains the applicant's FSAR supplement for the Non-EQ

Inaccessible Medium-Voltage Cable Program. The staff reviewed this section and finds the

program description is consistent with the material contained in Section B.1.15 of the LRA The

staff finds that the FSAR supplement provides an adequate summary of the program activities

as required by 10 CFR 54.21(d).

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Conclusions

Based on the statement that their proposed program for managing aging effects will be'

consistent with the GALL Report-Section XLE3,'the staff conclUdes that no further evaluation is

needed. :The applicant has, therefore, demonstrated that the effects-of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

FSAR supplement for this AMP and finds that It provides an adequate summary description of

the program, as required by 10 CFR 54.21(d). "

3.6.2.1.3 AMP for Electric Cables and Connections Not Subject to 10 CFR 50.49 EQ

Requirements -

The Non-EQ Insulated Cables and Connections Program is described in Section B.1.1 6 of the

LRA. The LRA credits this program with assuring that the intended functions of insulated '

cables and 'connections will be maintained consistent with the CLB through the period of !- .

extended operation. The program monitors-and assesses the condition of cables and -

connections that are affected by adverse localized environments. If an unacceptable condition'

or situation is identified, a determination is made`as' to whether the same condition or situation

is applicable to other accessible or inaccessible cables and connections. The staff reviewed

the LRA to determine whether the applicant has demonstrated that the Non-EQ Insulated

Cables and Connections Program will adequately manage the applicable aging effects

throughout the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Summary of Technical Information in the Application'

The applicant's Non-EQ Insulated Cables and Connections Program is discussed in LRA

Section B.1.16, -"Non-EQ Insulated Cables and Connections.' The applicant states that their

program will be consistent with the program described in the GALL Report, Section XL.E1,

'Electrical Cables and Connections Not Subject to 1 OCFR50.49 Environmental Qualification

Requirements". The applicant describes the program as a new program that will provide'

reasonable assurance that the intended functions of insulated cables and connections can be

maintained consistent with the current licensing basis through the period of extended operation.

The program will be effective for managing aging effects since it will incorporate proven

monitoring techniques, acceptance criteria, corrective actions,'and administrative controls. The

program will provide 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. And the program will be initiated

prior to the period of extended operation. "

The applicant's proposed FSAR supplement for Non-EQ Insulated Cables and Connections -

Program is discussed in LRA Section A.2.1.17. The applicant states that this program will apply

to accessible (i.e., able to be approached and viewed easily) insulated cables and connections

installed in structures within the scope of license renewal and prone to adverse localized

environments. The program will visually inspect a representative sample of accessible

insulated cables and connections for cable and connection jacket surface anomalies. The

program will be initiated prior-to the period of extended operation.

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Staff Evaluation

In LRA Section B.1.16, "Non-EQ Insulated Cables and Connections," the applicant discusses its

proposed program for managing aging effect due to exposure to heat (or radiation and air).

The LRA states that this program will be consistent with GALL AMP XL.E1, "Electrical Cables

and Connections," and will be initiated prior to the period of extended operation.

Based on the statement that their proposed program for managing the effects of aging will be

consistent with GALL AMP XL.E1, the staff concludes, pursuant with GALL Report guidelines,

that no further evaluation is needed. The applicant has, therefore, 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).

Section A.2.1.17 of Appendix A to the LRA contains the applicant's FSAR supplement for the

Non-EQ Insulated Cables and Connections Program. The staff reviewed this section and finds

the program description is consistent with the material contained in Section B.1.1 6 of Appendix

B to the LRA. The staff finds that the FSAR supplement provides an adequate summary of the

program activities as required by 10 CFR 54.21 (d).

Conclusions

Based on the statement that their proposed program for managing aging effects will be

consistent with GALL AMP X!.E1, the staff concludes that no further evaluation is needed. The

applicant has, therefore, demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.6.2.1.4 AMP for Electrical Cables Used in Instrumentation Circuits Not Subject to 10

CFR50.49 Environmental Qualification Requirement that are Sensitive to Reduction

in Conductor Insulation Resistance

The AMP for instrumentation cables that are sensitive to reduction in conductor insulation

resistance is described in Section B.1.8 of the LRA. The LRA credits the ANO-2 EQ Program,

i.e., the AMP described in Section B.1.8 of the LRA, with assuring that the intended functions of

instrumentation cables (that are sensitive to reduction in conductor insulation) will be

maintained consistent with the CLB through the period of extended operation. The staff

reviewed the LRA to determine whether the applicant has demonstrated that the ANO-2 EQ

Program will adequately manage the applicable aging effects throughout the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Summary of Technical Information in the Application

Table 3.6.1 of the LRA states that the aging management program evaluated as part of the

GALL Report (for electrical cables used in instrumentation circuits not subject to 10 CFR 50.49

EQ requirements that are sensitive to reduction in conductor insulation resistance) is not

applicable to ANO-2. The aging management program is not applicable since ANO-2

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instrumentation cables for high range radiation monitors and neutron flux detectors are subject

to 10 CFR 50.49 environmental qualification (EQ) requirements.

Staff Evaluation -

From the information presented in the LRA, the staff understands that instrumentation cables

used for high range radiation monitors and neutron flux detectors (that are sensitive to

reduction in conductor insulation resistance) will be subject the AMP defined by ANO-2's EQ

program which meets the requirements of 10 CFR 50.49. 10 CFR 50.49(c)(3), however, states

that environmental qualification of electric equipment important to safety located in a mild

environment are not included within the scope of 10 CFR 50.49; thus, these instrumentation

cables that are located in a mild environment (or not exposed to harsh environments) are not

explicitly required to be within the scope of 10 CFR 50.49. Based on its review,-the staff

concludes, as described in section 4.4 of this SER, that a plant's EQ program (which meets the

requirements of 10 CFR 50.49) is an acceptable AMP for license renewal. Therefore, subject

to a commitment (included as part of proposed FSAR supplement A.2.1.8 of the LRA), the staff

concludes that the applicant has demonstrated that the effects of aging will be adequately:

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation as required by 10 CFR 54.21 (a)(3).

Conclusions

Based on its review, the staff concludes, subject to an FSAR commitment that the subject

instrumentation circuits are within the scope of -10 CFR 50.49, that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation as

required by 10 CFR 54.21 (a)(3).

3.6.2.1.5 Conclusion

The staff has 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 associated aging effects. On the basis of its review, - the staff finds that the applicant has demonstrated that the effects of aging for these - components will be adequately managed, so that their intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). ; ,'

3.6.2.2 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

,Further Evaluation Is Recommended'

Summary of Technical Information in the Application..

In Section 3.6.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for electrical and l&C components. The applicant

provided information concerning how it will manage the following aging effects:

* electrical equipment subject to environmental qualification

* quality assurance for aging management of nonsafety-related components

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Staff Evaluation

For component groups for which GALL recommends further evaluation, the staff reviewed the

applicant's evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation.

3.6.2.2.1 Environmental Qualification (EQ) of Electrical Components

The aging analysis included as part of an environmental qualification program, which meets the

requirements of 10 CFR 50.49 that involve time-limited assumptions as defined by the current

operating term for the ANO-2 (i.e., 40 years), is a TLAA as defined in 10 CFR 54.3. TLAAs are

required to be evaluated in accordance with 10 CFR 54.21 (c)(1). The staff's review of the

environmental qualification program as a TLAA for license renewal is described in Section 4.4

of this SER.

3.6.2.2.2 Quality Assurance for Aging Management of Nonsafety-Related Components

The staff's review of quality assurance for aging management of non-safety-related electric

components is included as part of Section 3.0.4, "Quality Assurance Program Attributes Integral

to Aging Management Programs," of this SER.

In addition, the staff reviewed the applicant's further evaluations against the criteria contained in

Section 3.6.3.2 of the SRP-LR. The ANO-2 audit and review report documents the details of

the staff's audit and review.

Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations

conducted in accordance with the GALL Report are consistent with the acceptance criteria in

Section 3.6.3.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging

can be adequately managed so that the intended function(s) can be maintained consistent with

the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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

GALL Report

The applicant described the results of its AMR for electrical components in Table 3.6.2-1 of the

LRA. The staff reviewed these results to determine whether the applicant has demonstrated

that the effect of aging on the electrical components will be adequately managed during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.6.2.3.1 Phase Bus (Nonsegregated Bus for Station Blackout) and Connections

Summary of Technical Information in the Application

The applicant stated in Table 3.6.2-1 of the LRA that phase bus and connections subject to an

AMR (1) are constructed of aluminum, copper, and steel, (2) are exposed to heat and air, or an

outside weather environment consisting of temperatures up to 40 0C (105 0F), precipitation, and

negligible radiation, (3) are exposed to an ohmic heating environment consisting of

temperatures up to 72 0C (162 0F), (4) provide electrical connections to specified sections of an

electrical circuit to deliver voltage and current, and (5) require no AMP. The applicant did not

identify any aging effects from the environment (consisting of heat and air, or outside weather

up to 40 0C (105 OF), ohmic heating and air up to 72 'C (162 0F), and precipitation) that would

cause the loss of capability to provide electrical connections to specified sections of an

electrical circuit to deliver voltage, current, or signals.: The applicant concluded that an

environment consisting of temperatures up to 40 'C (105 0F), ohmic heat and air up to 72 0C

(162 OF), and precipitation has no significant aging effect on aluminum, copper, and steel (the

component parts from which the phase bus and connections are constructed); therefore, no

AMP is required.

Staff Evaluation

The staff agrees that an environment consisting of temperatures up to'40 `C (105 0F), ohmic'

heat and air up to 72 OC (162 OF), and precipitation has no significant aging effect on aluminum,

copper, and steel (the component parts from which phase bus and connections are

constructed); therefore, no AMP is required.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR,

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.2 Switchyard Bus (Switchyard Bus'for'Station Blackout) and Connections'

Summary of Technical Information in the Aowlication'

The applicant stated in Table 3.6.2-1 of the LRA that switchyard bus and connections subject to

an AMR (1) are constructed of aluminum and copper, (2) are exposed to an outdoor weather

environment consisting of temperatures up'to 40 CC (105 CF), precipitation, and negligible

radiation, (3) provide electrical connections to-specified sections of an electrical circuit to deliver

voltage, current, or signals, and (4) require no AMP. The applicant did not identify any aging

effects from the outdoor environment (consisting of temperatures up to 40 CC (105 'F) and

precipitation) that would cause the loss of the capability to provide electrical connections to

specified sections of an electrical circuit to deliver voltage, current, or signals. The applicant

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concluded that an environment consisting of temperatures up to 40 0C (105 OF) and

precipitation has no significant aging effect on aluminum and copper (the component parts from

which switchyard bus and connections are constructed); therefore, no AMP is required.

Staff Evaluation

The staff agrees that an outdoor weather environment has no significant aging effect on

aluminum and copper (the component parts from which switchyard bus and connections are

constructed); therefore, no AMP is required.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.3 High-Voltage Insulators

Summary of Technical Information in the Application

The applicant stated in Table 3.6.2-1 of the LRA that high-voltage insulators subject to an AMR

(1) are constructed of porcelain, galvanized metal, and cement, (2) are exposed to an outdoor

weather environment consisting of temperatures up to 40 0C (105 OF), precipitation, and

negligible radiation, (3) insulate and support an electrical conductor, and (4) require no AMP.

The applicant did not identify any aging effects from the outside environment (consisting of

temperatures up to 40 0C (105 OF) and precipitation) that would cause the loss of the capability

to insulate or support its associated electrical conductor. The applicant concluded that an

environment consisting of temperatures up to 40 0C (105 0F) and precipitation has no significant

aging effect on porcelain, galvanized metal, and cement (the component parts from which highvoltage insulators are constructed); therefore, no AMP is required.

Subsequently, in a letter dated August 18, 2004, the applicant, as part of an additional

response to RAI 2.5-1(c) included in Section 3.6.2.3.7.1 of this SE, indicated that high voltage

strain and suspension insulators that perform the function of insulating and supporting electrical

transmission conductors, like high voltage insulator that perform the function of insulating and

supporting switchyard bus described above, are within the scope of license renewal and subject

to an AMR. The applicant concluded that an environment consisting of temperatures up to

105'F and precipitation (including wind) has no significant aging effect on porcelain, galvanized

metal, and cement (the component parts from which high voltage insulators are constructed);

therefore, no aging management program is required.

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Staff Evaluation

The staff agrees that an outdoor weather environment has no significant aging effect on

porcelain, galvanized metal,-and cement (the component parts from which high-voltage

insulators are constructed); therefore, no AMP is required. On the basis of its review, the staff

therefore concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging can be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.6.2.3.4 Transmission Conductors

Summary of Technical Information in the ApDlication

By letter dated August 18, 2004, the applicant in a revised response to RAI 2.5-1 (c) states:

Based on the inclusion of Startup Transformer #2, transmission conductors,

strain and suspension insulators, and insulated cables are subject to aging

management review. Insulated cables were included in the ANO-2 LRA.

The transmission conductor component type includes transmission conductors

and the hardware used to secure the conductors to the insulators. The materials

for aluminum cable-steel reinforced (ACSR) transmission conductors are

aluminum and steel, and the environment is outdoor weather. Based on industry

guidance, potential aging effects and aging mechanisms are loss of conductor

strength due to general corrosion (atmospheric oxidation of metals) and loss of

material due to wear from wind loading.

.Corrosion in ACSR conductors is a very slow acting mechanism. Corrosion

rates are dependent on air quality..: ANO is located in a mostly agricultural area

with no significant nearby industries that could contribute to corrosive air quality.

Corrosion testing of transmission conductors at Ontario Hydroelectric showed a

30 percent loss of composite conductor strength of an 80-year-old ACSR

conductor. The Institute of Electrical and Electronic Engineers National Electrical

Safety Code (NESC) requires that tension on installed conductors be a

maximum of 60% of the ultimate conductor strength. Therefore, assuming a

30% loss of strength, there would still be significant margin between what is

required by the NESC and the actual conductor strength. In determining actual

conductor tension, the NESC considers various loads imposed by ice, wind, and

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temperature as well as length of conductor span. The transmission conductors in

scope for license renewal are short spans located within the high voltage

switchyard. The maximum span for ANO conductors subject to aging

management review is approximately 240 feet in length providing significant

margin to maximum design loading limits. ANO is in the medium loading zone;

therefore, the Ontario Hydroelectric heavy loading zone study is conservative

with respect to loads imposed by weather conditions.

The Ontario Hydroelectric test envelops the conductors at ANO, demonstrating

that the material loss on the ANO ACSR transmission conductors is acceptable

for the period of extended operation. This illustrates with reasonable assurance

that transmission conductors at ANO will have ample strength to perform their

intended function throughout the renewal term; therefore, loss of conductor

strength due to corrosion of the transmission conductors is not an aging effect

requiring management.

Loss of material due to mechanical wear can be an aging effect for strain and

suspension insulators that are subject to movement. Experience has shown that

transmission conductors do not normally swing and that when they do swing

because of substantial wind, they do not continue to swing for very long once the

wind has subsided. Wear has not been identified during routine inspection.

Therefore, loss of material due to wear is not an aging effect requiring

management for switchyard insulators.

Entergy reviewed industry operating experience and NRC generic

communications related to the aging of transmission conductors in order to

ensure that no additional aging effects exist beyond those identified above.

Entergy also reviewed ANO plant-specific operating experience, including

nonconformance reports, licensee event reports, and condition reports, and

documented interviews with transmission engineering personnel. Entergy's

review did not identify unique aging effects for transmission conductors beyond

those identified above.

Staff Evaluation

The staff agrees that an outdoor weather environment has no significant aging effect on

aluminum and steel (the component parts from which transmission conductors are

constructed); therefore, no aging management program is required. On the basis of its review,

the staff therefore concludes that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.6.2.3.5 Inaccessible Medium-Voltage Cables 1

During the site inspection that was conducted by the staff on November 15 through 19, 2004, a

walk-down of the electrical manholes was conducted.-, The staff noted that all of the observed

electrical manholes containing inaccessible medium-voltage cables were flooded, such that the

electrical cables in those manholes were submerged. The applicant stated that the program for

managing the aging of cables was not yet developed, but would be consistent with Generic

Aging Lessons Learned, and included a periodic inspection of the electrical manholes and the

removal of water. The staff noted that-the cables had been wetted for an indeterminate period

of time and requested that the applicant commit to cable testing in' addition to periodic .

inspections for the period of extended operation. In a letter dated February 28, 2005, the

applicant added a testing requirement to the AMP for inaccessible medium-voltage cables.

3.6.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the electrical components will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in the

electrical components, as required by 10 CFR 54.21 (d).

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3.7 Conclusion for Aging Management

The staff has reviewed the information in Section 3, "Aging Management Review Results," and

Appendix B, "Aging Management Programs and Activities" of the LRA. 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 FSAR Supplement program summaries and

concludes that the FSAR Supplement adequately describes the AMP's credited for managing

aging, as required by 10 CFR 54.21 (d).

With regard to these matters, the NRC staff has concluded that there is reasonable assurance

that the activities authorized by the renewed license will continue to be conducted in

accordance with the current licensing basis, and that any changes made to the ANO-2 current

licensing basis in order to comply with 10 CFR 54.21 (a)(3) are in accord with the ACT and the

Commission's regulations.

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4. TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aqinq Analyses

This section addresses the identification of time-limited aging analyses- (TLAAs). The applicant discussed the TLAAs in license renewal application (LRA) Sections 4.2 through 4.7.' The

Nuclear Regulatory Commission (NRC) staff documents its review of the TLAAs in Sections 4.2

through 4.7 of this safety evaluation report (SER).

The TLAAs'are certain plant-specific safety'analyses that are based on an explicitly assumed

40-year plant life. Pursuant to Title 10, Section 54.2i(c)(1), of the Code of Federal Regulations (10 CFR 54.21 (c)(1)); an applicant for licenserenewal must provide a list of TLAAs, as defined

in 10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21(c)(2), an applicant must provide a list of plant-specific exemptions granted under 10 CFR 50.12 that are based on TLAAs. -For any'such exemption,'

the applicant must provide an evaluation that justifies the continuation of the exemptions for the

period of extended operation.

4.1.1 Summary of Technical Information In the Application

The applicant evaluated calculations for Arkansas Nuclear One, Unit 2 (ANO-2), against the six

criteria specified in 10 CFR 54.3 to identify the TLAAs. The applicant indicated that it identified

the calculations that meet the six criteria by searching the current licensing basis (CLB), which

includes the Final Safety Analysis Report (FSAR); design-basis documents; the Statements of

Consideration for 10 CFR Part 54; NUREG-1800, "Standard Review Plan for Review of License

Renewal Applications for Nuclear Power Plants," (SRP-LR), issued July 2001; 'and Nuclear

Energy Institute (NEI) 95-10, Revision 3,' Industry Guideline for Implementing the

Requirements of 10 CFR Part 54-The License Renewal Rule," issued March 2001. The

applicant listed the following TLAAs that apply' to'ANO-2 in Table 4.1-2 of the LRA:

* reactor vessei neutron embrittlement' ' ''

* concrete containment tendon prestress

-metal fatigue

* environmental qualification of electrical e'quiprnent

* high-energy line break postulation based on fatigue cumulative usage factor

* low-temperature overpressure protection analyses

* fatigue analysis for the main steam supply lines to the turbine-driven auxiliary feedwater

lines

* leak before break

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* fatigue analysis of the containment liner plate

* containment penetration pressurization cycles

Pursuant to 10 CFR 54.21 (c)(2), the applicant stated that it identified no exemptions granted

under 10 CFR 50.12 that were based on a TLAA, as defined in 10 CFR 54.3.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to ANO-2 and discussed

exemptions based on TLAAs. The staff reviewed the information to determine whether the

applicant provided adequate information to meet the requirements of 10 CFR 54.21 (c)(1) and

10 CFR 54.21 (c)(2).

Title 10, Section 54.3, of the Code of Federal Regulations (10 CFR 54.3) defines TLAAs as

analyses that meet the following six criteria:

* involve structures, systems, and components (SSCs) within the scope of license

renewal, as delineated in 10 CFR 54.4(a)

* consider the effects of aging

* involve time-limited assumptions defined by the current operating term (e.g., 40 years)

* were determined by the applicant to be relevant in making a safety determination

* involve conclusions, or provide the basis for conclusions, related to the capability of the

SSC to perform its intended functions, as delineated in 10 CFR 54.4(b)

* are contained or incorporated by reference in the CLB

The applicant provided a list of common TLAAs from the SRP-LR and those TLAAs that are

applicable to ANO-2 in LRA Table 4.1-2.

Pursuant to 10 CFR 54.21 (c)(2), an applicant must provide a list of all exemptions granted

under 10 CFR 50.12 which it determines to be based on a TLAA and evaluates and justifies for

continuation through the period of extended operation. In its LRA, the applicant stated that it

performed a search of the ANO-2 docketed correspondence, the operating licenses, and the

FSAR, and that it evaluated each exemption in effect for TLAA applicability. The applicant

identified no TLAA-based exemptions. On the basis of the information the applicant provided

regarding the process it used to identify TLAA-based exemptions, plus the results of the

applicant's search, the staff finds that the applicant has found no TLAA-based exemptions

which would require justification for continuation through the period of extended operation to

satisfy 10 CFR 54.21 (c)(2).

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4.1.3 Conclusions

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), and has confirmed that no 10 CFR 50.12

exemptions have been granted on the basis of a TLAA, as required by 10 CFR 54.21 (c)(2).

The staff notes that the applicant did not initially identify the reactor coolant pump (RCP)

flywheel as subject to a TLAA, but included a TLAA for it in response to RAI 4.7.3-1.

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4.2 Reactor Vessel Neutron Embrittlement

The following regulations in 10 CFR Part 50 govern reactor vessel (RV) integrity:

* Section 50.60 requires that all light-water reactors (LWRs) meet the fracture toughness,

pressure-temperature limits, and material surveillance program requirements for the

reactor coolant boundary as set forth in Appendices G and H to 10 CFR Part 50.

* Section 50.61 contains fracture toughness requirements for protection against

pressurized thermal shock.

The design bases of ANO-2 contain calculations and analyses addressing the effects of

neutron irradiation embrittlement of the RV. The analyses that evaluated the reduction of

fracture toughness of the ANO-2 RV for 40 years are TLAAs. The applicant updated the

analyses for the initial 40-year license to address the additional 20 years of operation (i.e., 60

years total) for license renewal. The ANO-2 Reactor Vessel Integrity Program described in

Appendix B to the LRA will ensure that the time-dependent parameters used in the TLAAs and

described below remain valid through the period of extended operation. The applicant

projected the RV neutron embrittlement TLAAs to the end of the period of extended operation in

accordance with 10 CFR 54.21 (c)(1)(ii), as summarized below.

The application included three TLAAs for evaluation of the RV beltline materials, including (1)

calculation of the end of extended license Charpy V-notch upper-shelf energy (USE) values for

each beltline material, (2) calculation of the end of extended license pressurized thermal shock

(PTS) reference temperature (RT) value (i.e., RTPTS values) for each beltline material, and (3) a

description of the pressure-temperature (P-T) limit calculations for 48 effective full-power years

(EFPYs). The applicant will prepare revised P-T limit curves for extended operation and submit

them before reaching 32 EFPYs (as stated in Section 5.2.4.3.2 of the Final Safety Analysis

Report (FSAR) Supplement). Each analysis has been updated to consider 20 years of

additional plant operation. The TLAAs take into account the effects of the additional extended

operating period neutron irradiation on the previous calculated end of license USE, RTPTS, and

P-T limit values for the RV at ANO-2, and they base the evaluations through 48 EFPYs of

power operation.

The applicant assumed a capacity factor of 80 percent for the TLAA associated with RV

neutron embrittlement evaluations that it described in Section 4.2 of the LRA. The applicant

based these evaluations on end of life (EOL) fluences corresponding to 48 EFPYs of operation.

In Request for Additional Information (RAI) 4.2-1, the staff asked the applicant to justify the

assumed 80-percent capacity factor for the period of extended operation, in light of similar

plants achieving and projecting capacity factors of 90 percent or greater. The staff also

requested that the applicant justify the estimated 48-EFPY fluence for ANO-2, or, if the

applicant cannot justify a 48-EFPY fluence, it should provide the results of revised evaluations

of USE for higher levels of fluence projected to the end of the period of extended operation.

In response to RAI 4.2-1, the applicant stated that the ANO-2 end of license fluence estimate

for the period of extended operation is based on 48 EFPYs, which assumes a plant capacity

factor of 80 percent over 60 years. This is consistent with the method used to calculate 40-year

fluence estimates the applicant reported in its response to Generic Letter 92-01. At present,

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the lifetime capacity factor for ANO-2 through 26 years of operation is approximately 80

percent. Therefore, it is reasonable to assume a lifetime capacity factor of 80 percent when

evaluating 60 years of operation.

The applicant also stated that the Reactor Vessel Integrity Program addresses the impact on

fracture toughness of operation at capacity factors in excess of 80 percent. As the applicant

stated in Section 4.2 of the LRA, the ANO-2 Reactor Vessel Integrity Program described in

Appendix B to the LRA will ensure that the time-dependent parameters (e.g:, end of license

fluence) used in the TLAA remain valid through the period of extended operation. As capsules

are pulled and tested, the applicant will perform fluence updates and end of license vessel

fluence extrapolations. The applicant will compare the updated fluence projections to the 48-

EFPY fluence estimates reported in the LRA. If the revised end of license fluence

extrapolations exceed the values provided in the LRA, then the applicant will update the

corresponding fracture toughness parameters (adjusted reference temperature (ART), USE,

and RTpTs) accordingly. The staff finds the response acceptable and considers this issue

closed.

4.2.1 Charpy Upper-Shelf Energy

Appendix G to 10 CFR Part 50 requires that RV beltline materials must have USE values in the

transverse direction for the base metal, and along the weld for the weld material, according to

the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the;

ASME Code) of no less than 75 foot-pounds (ft-lb) (102 J) initially, and USE values throughout

the life of the vessel of no less than 50 ft-lb (68 J). However, USE values below these criteria

may be acceptable if the applicant demonstrates, in a manner approved by the Director of the

Office of Nuclear Reactor Regulation, that the lower values of USE will provide margins of

safety against fracture equivalent to those required by Appendix G to Section Xl of the ASME

Code. -Regulatory Guide (RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel

Materials," provides an expanded discussion regarding the calculations of USE values and

describes two methods for determining USE values for RV beltline materials, depending on if a

given RV beltline material is represented in the plant's RV material surveillance program (i.e.,

Appendix H to 10 CFR Part 50).

4.2.1.1 Summary of Technical information in the Application

Section 4.2.1 of the LRA addresses the requirement that RV beltline materials must maintain a

USE value of not less than 50 ft-lb throughout the life of the vessel, unless the applicant

demonstrates, in a manner approved by the Director of the Office of Nuclear Reactor - ;

Regulation, that lower values of USE will provide margins of safety against fracture that are

equivalent to those required by Appendix G to Section Xl of the ASME Code. The applicant

stated that it calculated the USE values through the period of extended operation using

guidance from RG 1.99, Revision 2. The applicant used a value of 48 EFPYs as the end of

extended license criterion for the RV. The LRA contains the information derived from the USE

analysis. ,The applicant summarized the end of extended operating period USE analyses for

the ANO-2 RV beltline materials'in Table 4.2-1 of the LRA. The LRA includes a list of all

beltline 'naterials, the weight percent copper in the steel, the end of license fluence for the RV

located6one-quarter of the way through the RV wall from the vessel's inside surface (i.e., 1/4

thickness (T) of the vessel), and the initial arnd final USE values.

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The applicant calculated the best estimate fluence at the inside (wetted) surface of the RV

using the methodology reported in the Babcock & Wilcox report BAW-2241 P-A, Revision 1,

"Fluence and Uncertainty Methodologies,' issued April 1999. The NRC's Division of Systems,

Safety, and Analysis staff approved this methodology, which meets the uncertainty

requirements of RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure

Vessel Neutron Fluence," issued March 2001.

The applicant concluded that the end of extended license USE results for 48 EFPYs are above

the screening criterion of 50 ft-lb (68 J). The applicant stated that it projected the calculations

through the period of extended operation, and met the requirements of 10 CFR 54.21 (c)(1 )(ii).

4.2.1.2 Staff Evaluation

The technical staff reviewed the TLAA for USE to identify aspects of the TLAA that are

impacted by the additional fluence levels that will occur during the period of extended operation.

The review included an independent evaluation of material chemistries and properties, as listed

in the NRC's Reactor Vessel Integrity Database (RVID), for consistency with the data listed in

the LRA.

The staff performed an independent calculation of the end of extended license USE values for

the beltline materials the applicant used to fabricate the ANO-2 RV: The staff applied Position

1.2 of RG 1.99 to estimate the percent loss of USE as a function of copper content and neutron

fluence for the beltline materials, as evaluated using the 48-EFPY end of extended license

fluence.

With regard to the staff's independent USE analysis of ANO-2 beltline materials, the staff

confirmed that the most limiting beitline material it identified for the ANO-2 RV is the same as

that identified by the applicant. Although the staff's calculated USE values for the limiting RV

beltline materials were not always consistent with the applicant's calculated USE values, both

the staff's and the applicant's USE analyses confirm that the USE values for the ANO-2 beltline

materials will remain at or above the 50 ft-lb acceptance criteria of Appendix G to 10 CFR Part

50 through the expiration of the period of extended operation for the unit.

The staff determined that the 48-EFPY (60-year) USE assessment for the RV beltline materials

is bounded (limited) by the USE value for the intermediate shell longitudinal weld 2-203 A. The

staff calculated the projected USE value for this material to be 54 ft-lb through the expiration of

the period of extended operation for the unit. This material meets the staff's end of license 50

ft-lb acceptance criterion for USE. The staff also performed a 54 EFPY USE assessment for

the ANO-2 RV beltline materials and calculated a limiting USE of 52.5 ft-lb through the

expiration of the period of extended operation.4

4 Although the design basis used in the LRA for the period of extended operation is 48 EFPY, the staff also

performed additional USE calculations for the RV beitline materials at 54 EFPY. The staff performed the additional

calculations to resolve a question raised by the Advisory committee on Reactor Safety (ACRS) during the ACRS

Subcommittee meeting on the ANO-2 LRA. The staff calculated the limiting USE value to be 52.5 ft-lb at 54 EFPY.

The staffs acceptance criterion on USE, as stated in 10 CFR Part 50, Appendix G, is a minimum of 50 ftl-ib at the

end of licensed life of the reactor. Thus, the ANO-2 RV will acceptable for USE even if an addition 6 EFPY Is added

to the 48 EFPY design basis for the period of extended operation.

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The applicant did not include upper/intermediate shell weld 8-203 in Table 4.2-1 of the LRA.

This material has the highest copper content (0.216 weight percent) of the vessel beltline

materials. However, as listed in RVID,-it has-only 14 percent of the fluence of the limiting

beltline welds covered by the LRA. Appendix.G to 10 CFR Part 50, defines the RV beltline or

beltline region as the region of the RV (shell material including'welds, heat affected zones, and

plates or forgings) directly surrounding the effective height of the active core and adjacent

regions of the RV that are predicted to experience sufficient neutron radiation damage to be

considered in the selection of the most limiting material with regard to radiation'damage. The

staff concurred with the applicant that this'weld is not the limiting material of the RV and that it

has sufficiently low fluence. Therefore, this weld would not experience significant neutron

radiation damage, and it can be excluded from the list of beltline materials.-

The staff determined that the methods used by the applicant for the 60-year USE assessment

for the RV beltline materials are consistent with accepted methods and NRC guidance

documents. The staff evaluation concluded that the USE values for the ANO-2 beltline

materials will remain at or above the 50 ft-lb acceptance criteria of Appendix G to 10 CFR Part

50 through the expiration of the period of extended operation.

The staff confirmed that all RV beltline materials will continue to satisfy the USE value

requirements of Appendix G to 10 CFR Part 50 through the end of the period of extended

operation for ANO-2.' The staff therefore concludes that the applicant's TLAA for calculating the

USE values of the RV beltline materials is acceptable because it meets the requirements of 10

CFR 54.21 (c)(1 )(ii) and will ensure that the RV materials will have adequate USE levels and

fracture toughness through the end of the period of extended operationd'.

4.2.2 Pressurized Thermal Shock

Title 10, Section 50.61, of the Code of Federal Regulations (10 CFR 50.61) provides the

fracture toughness requirements for protecting the RVs of PWRs against the consequences of

PTS. The NRC requires licensees to assess the RV materials' projected values for RTPTs

through the end of their operating licenses. If approved for license renewal, this would include

TLAAs for PTS up through the end of the period of extended operation for ANO-2, assumed to

be 48 EFPYs. The rule requires each licensee to calculate the end of license RTPTs value for

each material located within the beltline of the reactor pressure vessel.- The RTpTs value for

each beltline material is the sum of the unirradiated nil-ductility reference temperature (RTNDT)

value, a shift in the RTNDT value caused by exposure to high energy neutron irradiation of the

material (i.e., ARTNDT) value, and an additional margin value to account for uncertainties (i.e., M

value). 'Title 10, Section 50.61, of the Code of Federal Regulations (10 CFR 50.61) also . '-

provides screening criteria against which the applicant should evaluate the calculated RTpTs

values. For RV beltline base metal materials' (forging or plate materials) and longitudinal (axial)

weld materials, the NRC considers the materials to provide adequate protection against PTS

events if the calculated RTPTs values are'less'than or equal to 132 0C (270 0F). For RV beltline

circumferential weld materials, the NRC cbnsiders the materials to provide adequate protection

against PTS events if the calculated RTpTs values are less than or equal to 149 'C (300 OF).

Additionally, 10 CFR 50.61 discusses the calculations of RTPTs values and describes two

methods for determining RTPTs for RV materials, depending on if a given RV beltline material is

represented in the plant's RV material surveillance program (i.e., Appendix H to

10 CFR Part 50). - - :

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4.2.2.1 Summary of Technical Information in the Application

Section 4.2.2 of the LRA addresses the 10 CFR 50.61 requirement for protection of the RV

from PTS. The applicant stated that the screening criteria in 10 CFR 50.61 are 1320C (270 OF)

for plates, forgings, and axial welds, and 149 OC (300 OF) for circumferential welds. According

to the regulation, if the calculated RTPTS values for the beltline materials are less than the

screening criteria, then the RV is acceptable with respect to risk of failure during PTS

transients. In this part of the LRA, the applicant described the projected values of RTP over

the period of extended operation (assumed to be 48 EFPYs in the LRA) to demonstrate that the

screening criteria are not violated. The applicant stated that it carried out this analysis and that

the results do not exceed the screening criteria. The applicant stated that it projected the

calculations through the period of extended operation and met the requirements of

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

Pursuant to 10 CFR 50.61 (b)(1), which provides rules for protection against PTS for

pressurized-water reactors (PWRs), the NRC requires licensees to assess the projected RT

values whenever a significant change occurs in projected values of RTpTs or upon request for a

change in the expiration date for the operation of the facility. For ANO-2 license renewal, RTpTs

values are calculated for 48 EFPYs.

The applicant obtained fluence values at 48 EFPYs for ANO-2 at the clad/base metal interface

using the methodology described in Reference 4.2-1, as described in Section 4.2.1 above. This

method meets the uncertainty requirements of RG 1.190. The applicant estimated a peak

inside vessel/clad interface fluence of 5.0896x1 019 n/cm2 at 48 EFPYs for the lower shell plates.

Title 10, Section 50.61 (b)(2), of the Code of Federal Regulations (10 CFR 50.61 (b)(2))

establishes screening criteria for RTpTs as 132 0C (270 OF) for plates, forgings, and axial welds,

and 149 0C (300 0F) for circumferential welds. Table 4.2-2 of the LRA provides the values for

RTPTs at 48 EFPYs for ANO-2. The applicant calculated the projected RTPTS values using RG

1.99, Revision 2, Positions 1 and 2, and they are all within the established screening criteria for

48 EFPYs. The limiting beitline material is the lower shell plate C-8010-1, with a 48-EFPY

RTpTs of 50.3 0C (122.6 OF), which is well below the limit of 132 0C (270 OF). Therefore, the

applicant has evaluated RTPTS for ANO-2 in accordance with 10 CFR 54.21 (c)(1)(ii) and

determined it to be acceptable for the period of extended operation.

A comparison of copper content, nickel content, and unirradiated RTNDT values for ANO-2

beltline materials listed in Table 4.2-2 to the values reported in the NRC RVID2 indicates slight

differences for selected plate and weld materials. Chemistry factors for surveillance materials

have been revised to reflect the use of RG 1.99, Revision 2, Position 2.1. These differences

are not significant and do not alter the conclusion that RTpTs values are within the established

screening criteria for 48 EFPYs. The upper shell to intermediate shell circumferential weld

material is listed in RVID2 but is not included in Table 4.2-2 since it is not a limiting material in

accordance with the beltline definition provided in 10 CFR 50.61.

4.2.2.2 Staff Evaluation

The applicant provided its PTS assessment for the period of extended operation for ANO-2 RV

beltline materials. The applicant included the assessment for each material in Table 4.2-2 of

the LRA. In reviewing the applicant's description of the PTS analysis, the staff evaluated the

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methods the applicant used to calculate RTVIS values and examined the data and results of the

analysis, as summarized in Table 4.2-2 of the LRA.

The staff performed an independent calculation'of the RTpTs values for the ANO-2 beltline RV

materials, based on'the projected 48-EFPY neutron fluence values for the materials. The

staff's independent assessment of the most limiting beltline material established that the

applicant based the LRA on'material informaition'consistent with the RVID data; 'In reviewing

the applicant's description of the PTS analysi,' the'staff examined the data'and results of the"

analysis, as summarized in Table 4.2-2 of the LRA The staff's calculated RT,.s values for the

RV beltline materials were equivalent to the RTITs values calculated by the applicant. Both the

staff's and the applicant's PTS analyses confirm that the RTpTs values for the ANO-2 beltline

materials will remain below the PTS screening'criteria'of 10 CFR 50.61 through the period of

extended operation. -

The staff determined that the lower shell plate C-801 0-1 is the most limiting material and

calculated the 48-EFPY RTPTs value for this material to be 50.3 OC (122.6 OF).

All of the beltline materials are below the 10 CFR 50.61 screening criteria. Based on these

considerations, the staff finds the applicant's'*TLAAs for protecting the ANO-2 vessel against

PTS to be' acceptable because the'staff confirmed that the applicant established the RTPTS

values for the RV beltline materials of ANO-2 with'methods consistent with NRC guidance

documents. The staff therefore concludes that the applicant's TLAA for calculating'RTns

values for the RV beltline materials of ANO-2 is acceptable because it meets the requirements

of 10 CFR 54.21 (c)(1)(ii) and will ensure that -the RV materials will have sufficient protection

against PTS events through the end of the periodof extended operation. '

4.2.3 Pressure-Temperature Limits .; -

The NRC designed the requirements in Appendix G to 10 CFR Part 50 to protect the integrity of

the reactor coolant pressure boundary in'nucleai power plants. The applicant established the

P-T limits by calculations that use the materials and fluence data obtained through the unitspecific Reactor Surveillance Capsule Program. Normally, the P-T limits are calculated for

several years into the future and remain valid for an established period of time, not to exceed

the expiration date of the current operating license.

The staff evaluates the P-T limit curves based on NRC regulations and guidance. Appendix G

to 10 CFR Part 50 requires that P-T limit curves be at least as conservative as those obtained

by applying the methodology of Appendix G'to Section Xl of the ASME Code. Appendix G to

10 CFR Part 50 also provides minimum temperature'requirements that an applicant must

consider in the development of the P-T iirnit'curves. Section 5.3.2 of the SRP-LR provides an

acceptable'method for determining the P-T limit curves'for ferritic materials in the beltline'of the

RV based on the 'linear elastic fracture mechanics methodology of Appendix G to Section Xi of

the ASME Code. The critical locations in the RV beltline region for'calculating heatup and

cooldown P-T curves are the 1/4T 4Tlocations, which correspond to the maximum depth

of the postulated inside surface and outside suiface defects,'respectively.'

f4-9
4.2.3.1 Summary of Technical Information in the Application

In Section 4.2.3 of the LRA, the applicant addressed the requirement in Appendix G to

10 CFR Part 50 that it accomplish normal operations (including heatup, cooldown, and transient

operating conditions) and pressure test operations of the RV. within established P-T limits. The

applicant established these limits by calculations that use the materials and fluence data

obtained through the ANO-2 Reactor Surveillance Capsule Program. The applicant based the

LRA on an approved license amendment request for reactor coolant system (RCS) P-T limit

curves for 32 EFPYs. The curves account for a 7.5-percent power upgrade and were

developed using ASME Code Case N-640, "Alternative Reference Fracture Toughness for

Development of P-T Limit Curves, Section Xl, Division 1," as well as Code Case N-588,

"Alternative to Reference Flaw Orientation of Appendix G for Circumferential Welds in Reactor

Vessels, Section Xl, Division 1." In addition, the low-temperature overpressure protection

(LTOP) limits are based on the licensed P-T limit analysis. The applicant will also update LTOP

limits as required.

Appendix G to 10 CFR Part 50 requires that heatup and cooldown of the reactor pressure

vessel be accomplished within established P-T limits. The applicant established these limits by

calculations that use materials and fluence data obtained through the unit-specific Reactor

Vessel Surveillance Capsule Program. Normally, the P-T limits are calculated for several years

into the future and remain valid for an established period of time not to exceed the operating

license expiration date.

The applicant submitted a license amendment request for RCS P-T curves for 32 EFPYs

(References 4.2-2 and 4.2-3). The curves specify limits on RCS pressure and temperature for

up to 32 EFPYs with a 7.5-percent power uprate. The applicant based these P-T curves on a

fluence analysis that complies with RG 1.190 and utilizes ASME Code Cases N-640 and N-588.

Based on the ANO-2 P-T limit curves, the operating window at 48 EFPYs is sufficient to

conduct normal heatup and cooldown operations. The applicant based LTOP limits on the

licensed P-T limit analyses and will update them as required.

The applicant has projected calculations of P-T limits for ANO-2 to the end of the period of

extended operation, in accordance with 10 CFR 54.21 (c)(1)(ii).

4.2.3.2 Staff Evaluation

The current P-T limit curves for ANO-2 are acceptable through 32 EFPYs of power operation.

In accordance with 10 CFR 50.90, licensees must submit new P-T limit curves for operating

reactors to the NRC for review and approval. The licensee may then implement the new

approved curves into the technical specifications (TSs) for the reactor units before the

expiration of the most current P-T limit curves. The applicant must submit the P-T limit curves

for the ANO-2 RV for the period of extended operation for NRC review and approval. The

applicant may then implement the P-T limit curves into the TS before the operation of the

reactors during the period of extended operation. The staff's review and approval of the

extended-period-of-operation P-T limit curves will ensure that the units will be operated in a

manner that ensures the integrity of the RCS during the period of extended operation.

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4.2.4 FSAR Supplement . *1

Sections A.2.2.1.1, A.2.2.1.2, and A.2.2.1.3 of Appendix A to the LRA provides the applicant's

FSAR Supplement for the TLAA on RV neutron embrittlement. The applicant's appropriate

consideration of RV neutron embrittlement, including the effects of neutron irradiation on the

PTS, USE, and P-T limit assessments, constitutes the basis for the staff's acceptance of the

licensee's TLAA evaluation for the period of extended operation.

The applicant did not include a corresponding FSAR Supplement summary description for

Table 4.2-2 of the LRA. Table 4.2-2 contains a PTS evaluation for the ANO-2 RV through the

expiration of the period of extended operation. The staff notes that the applicant included the

corresponding table for the USE extended life evaluation '(Table 4.2-1) in the FSAR

Supplement. In RAI 4.2-2, the staff requested that the applicant include a corresponding FSAR

Supplement summary description for LRA Table 4.2-2 in its FSAR Supplement.

In its response to RAI 4.2-2, the applicant responded that 10 CFR 54.21(d) requires a safety

analysis report (SAR) Supplement that contains a summary description of the programs and

activities for managing the effects of aging and the evaluation of TLAAs for the period of

extended operation. Table 4.2-2 of the LRA provides data for and tabular results of the

applicant's evaluation of the RV PTS TLAA for the period of extended operation. Table 4.2-2 is

neither the evaluation of the TLAA, nor a summary description of the evaluation. Pursuant to

10 CFR 54.21(d), the applicant provided Section A.2.2.1.2 of the LRA as the SAR Supplement

summary description of the evaluation of the TLAA for PTS, the results of which are shown in

Table 4.2-2 of the LRA.

The ANO-2 SAR does not contain a table equivalent to Table 4.2-2 of the LRA. The applicant

identified the limiting beltline material with respect to PTS within the text of SAR Section

5.2.4.3.3, as well as in the proposed SAR Supplement, in Appendix A to the LRA. The ANO-2

SAR does contain a table summarizing the results of the RV USE evaluation. Correspondingly,

the proposed SAR Supplement includes an update to this table to account for the period of

extended operation. However, no equivalent PTS table is required to maintain the CLB as

defined in the ANO-2 SAR for the period of extended operation. The staff finds the response

acceptable and considers this issue closed.

On the basis of the staff's review of the FSAR Supplement summary descriptions for the TLAAs

on USE, PTS, and P-T limits, as well as the applicant's response to RAI 4.2-2, the staff

concludes that the FSAR Supplement summary descriptions in Sections A.2.2.1.2, A.2.2.1.2,

and A.2.2.1.3 of the LRA of the evaluations described above are adequate.

4.2.5 Conclusions

The staff has reviewed the TLAAs regarding the maintenance of acceptable Charpy USE levels

for the RV materials at ANO-2, as well as the RV's ability to resist failure during postulated PTS

events. The staff determined that the applicant's TLAAs for Charpy USE and PTS for ANO-2

meet the respective requirements of Appendix G to 10 CFR Part 50 and 10 CFR 50.61 for RV

beltline materials, as evaluated to the end of the period of extended operation. Therefore, on

the basis of this review, the staff concludes that, pursuant to 10 CFR 54.21 (c)(1)(ii), the TLAAs

on USE and PTS have been projected to the expiration of the period of extended operation for

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ANO-2, and that the applicant will adequately manage the effects of aging on the pressure

boundary function for the period of extended operation.

Pursuant to 10 CFR 50.90, the applicant will submit the end of the extended operating term P-T

limit curves for ANO-2 before to the expiration of the 32 EFPY. P-T limit curves for the plant.

The staff's review and approval of the period of extended operation P-T limit curves will ensure

that ANO-2 will operate in a manner that ensures the integrity of the reactor coolant pressure

boundary for the period of extended operation, and that the end of the extended operating term

P-T limit curves will satisfy the requirements of 10 CFR 54.21 (c)(1 )(ii) and Appendix G to

10 CFR Part 50 for the period of extended operation.

The staff also concludes that the FSAR Supplement contains adequate summary descriptions

of the evaluations of the the TLAAs on neutron irradiation embrittlement of RV beltline materials

(i.e., the TLAAs on USE, PTS, and P-T limits), as required by 10 CFR 54.21 (d).

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4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the static design load may fail

from fatigue. Metal fatigue of componentsimay have been evaluated based on an assumed '

number of transients or cycles for the current operating term. -IThe NRC reviews the validity of

such metal fatigue analyses for the period of extended operation. NUREG-1 801, "Generic

Aging Lessons Learned (GALL) Report,".identifies fatigue aging-related effects that require

evaluation as possible TLAAs pursuant to 10 CFR 54.21 (c). The SRP-LR summarizes each of

these, and the applicant presented them in Section 4 of the LRA. .: . . ; .

The applicant stated that the analyses of metal fatigue at ANO-2 are TLAAs for Class 1 and

selected'non-Class 1 mechanical components'within the scope of license renewal. Fatigue

evaluations are TLAAs since they are based 'on design transients defined for the life of the plant

(SAR Section 5.2.1.5). Section III of the ASME Code requires a fatigue analysis for each Class

1 component, considering all transient loads based on the anticipated number of transients.

The fatigue analyses require the calculation of cumulative usage factors (CUFs) based on the

fatigue'propeirties of the material and thelexp6cted fatigue service of the individual component.

The ANO-2 Class 1 items that received a code fatigue evaluation in accordance with ASME -

Code, Section III, Subsection NB, include the pressurizer, the RV, the control element drive

mechanism housing assembly, steam generators, RCPs, and the RCS piping. i

Non-Class 1 pressure vessels, heat exchangers, storage tanks, and pumps at ANO-2 are

designed in accordance with'ASME Code, Sections Vill or ll, Subsections NC or ND'(Classes -

2 or 3).' :Some tanks and pumps are designed to other industry codes and standards, such as

American Water Works Association (AWWA) standards and Manufacturer's Standardization

Society (MSS) standards. However, only ASME Code, Section Vill, Division 2, and ASME

Code, Section ll, Subsection NC-3200, include fatigue design requirements.'-

Fatigue evaluations are TLAAs since they are based on design transients defined for the life of

the plant (SAR Section 5.2.1.5). Section 4.3.1:1 of this SER evaluates Class I metal fatigue

TLAAs, and Section 4.3.1.2 of this SER evaluates non-Class 1 metal fatigue TLAAs.

4.3.1 Summary of Technical Information In the Application

4.3.1.1 Fatigue of ASME Class 1 Components

The applicant stated that it performed fatiguie evaluations, contained in calculations and stress'

reports, in the design of the ANO-2 Class 1 components in accordance with the requirements

specified in ASME Section III for Class 1 rcomponents. Because the applicant based these

fatigue evaluations on a number of cycles assumed for a 40-year plant life, these evaluations

are TLAAs. . a 4

The ability to withstand cyclic operation without fatigue failure is expressed in terms of the

required calculation' of CUFs for ASME Code,'Sectio'n Ill, Class 1 components. The applicant

compiled the ANO-2 CUFs for the Class 1'cormiponents designed in accordance with ASME

Code, Section III; considering the RCS design transients used to develop the CUFs for the RV,'

the control element drive mechanism housing assembly, the pressurizer, steam generators,

RCPs, and RCS piping. The applicant stated that it reviewed the number of RCS design

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transients accrued through 2002 for ANO-2 and linearly extrapolated them to 60 years of

operation, as reported in Table 4.3-1 of the LRA. In all instances, the applicant found the

number of RCS design transients assumed in the original design to be acceptable for 60 years

of operation, and the CUFs will therefore remain within the ASME Code, Section 1II, Class 1

fatigue limit. On this basis, the applicant concluded that the metal fatigue TLAAs will remain

valid for the period of extended operation, in accordance with,10 CFR 54.21(c)(1)(i). The

applicant also stated that it monitors RCS design transients through the Fatigue Monitoring

Program, which Appendix B discusses.

4.3.1.2 Fatigue of ASME Non-Class 1 Components

The applicant stated that each mechanical system it reviewed as part of the integrated plant

assessment and reported in Sections 3.2 through 3.4 of the LRA was also screened to identify

potential metal fatigue TLAAs. The applicant accomplished this using a screening process to

identify non-Class. 1 components that may have normal/upset condition operating temperatures

in excess of 104 0C (220 0F) for carbon steel or 132 0C (270 OF) for austenitic stainless steel.

The following subsections present the results of the TLAA fatigue review for non-Class 1

mechanical systems within the scope of license renewal.

4.3.1.2.1 Piping and In-Line Components

Mechanical systems containing piping components that exceed the screening criteria listed

above include primary sampling, low-pressure safety injection/shutdown cooling, containment

spray, chemical and volume control system (CVCS), emergency diesel generator, alternate

alternating current diesel generator, containment penetrations, main feedwater, main steam,

emergency feedwater, and blowdown/steam generator secondary. The piping components that

exceed the screening criteria were designed to American National Standards Institute (ANSI)

B31.1, which does not require an explicit fatigue analysis but specifies allowable stress levels

based on the number of anticipated thermal cycles. Specifically, a stress reduction is not

required in the design of piping that is not expected to experience more than 7000 cycles.

These piping components were evaluated for their potential to exceed 7000 thermal cycles in

60 years of plant operation. Only the RCS hot-leg sampling piping potentially exceeds 7000

cycles during the period of extended operation. Therefore, the applicant revised a pertinent

calculation to justify RCS sampling to occur at any reasonable frequency for 60 years of

operation without exceeding the allowable number of cycles. On this basis, the applicant

concluded that the fatigue analyses for all non-Class 1 components at ANO-2 remain valid for

the period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i).

4.3.1.2.2 Pressure Vessels, Heat Exchangers, Storage Tanks, and Pumps

Only non-Class 1 pressure vessels, heat exchangers, storage tanks, and pumps designed and

fabricated in accordance with ASME Code, Section Vill, Division 2 or ASME Code, Section III,

NC-3200 require evaluation for thermal fatigue. The NRC does not require fatigue evaluation

for other design codes (e.g., ASME Code, Section Vil, Division 1; AWWA; or MSS), and

components designed and fabricated with these codes are suitable for the period of extended

operation without further evaluation. The applicant's engineering evaluations identified no nonClass 1 pressure vessels, heat exchangers, storage tanks, or pumps requiring evaluation for

thermal fatigue.

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4.3.1.3 Response to Industry Experience ; r

The nuclear'industry reviews events that occur at nuclear power plants and new findings

discovered by research. Industry experience arid new research have found fatigue issues such

as thermal stratification and environmentally assisted fatigue that were not considered in the

original plant designs. Some of these findings impact the fatigue analysis and result in the

issuance of NRC generic communications. isThe following sections discuss the concerns that

-are directly related to metal fatigue.,.

4.3.1.3.1 Generic Safety Issue 190, "Envirenmentally Assisted Fatigue" , *~ , . tk , -

Recent test data indicate that certain environmental effects (e.g., temperature, oxygen, and

strain rate) in the primary systems of LWRs'could result in greater susceptibility to fatigue than

fatigue analyses would predict based on the ASME Code, Section 1II, design fatigue curves.

The ASME design fatigue curves were based on laboratory tests in air at low temperatures.

Although the failure curves derived from laboratory tests were adjusted to account for effects

such as data scatter, size effect, and surface finish, the NRC is concerned that these

adjustments may not be sufficient to account for actual plant operating environments.

The NRC implemented a fatigue action plan to systematically assess fatigue issues in operating

plants. As reported in SECY-95-245, which documented the results of the fatigue action plan,

the NRC believes that no immediate staff or licensee action is necessary to deal with the fatigue

issues addressed by the fatigue action plan. In addition, the staff concluded that it could not

justify requiring a backfit of the environmental fatigue data to operating plants. However, the

NRC concluded that because metal fatigue effects increase with service life, the action plan

fatigue issues should be evaluated for any proposed period of extended operation for license

renewal. Specifically, as part of the resolution of Generic Safety Issue (GSI)-1 66,' which

resulted in the initiation of GSI-1 90, "Environmentally Assisted Fatigue," the NRC will consider

the need to evaluate a sample of components of high-fatigue usage applying the latest

available environmental fatigue data. The NRC intends to ensure that components will continue

to perform their intended functions during the period of extended operation associated with

license renewal. -

As a part of the effort to close GSI-1 66 for operating nuclear power plants during the current

40-year license term, Idaho National Engineering Laboratory evaluated fatigue-sensitive

component locations at plants designed by the four U.S. nuclear steam supply system vendors.

NUREG/CR-6260 provides the results of those evaluations. Section 5.2 of NUREG/CR-6260

identifies the following component locations to be most sensitive to environmental effects for

older Combustion Engineering (CE) plants (these locations and the subsequent calculations are

directly relevant to ANO-2):

* reactor vessel shell and lower head

* reactor vessel inlet and outlet nozzles

* rsurge line

*; charging nozzle

* safety injection nozzle -

* shutdown cooling system Class 1 piping

T al .. o

Table 5-43 of NUREG/CR-6260 summarizes the 'evaluation of the six limiting locations for the

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current term of operation (40 years) and the period of extended operation (60 years in total). Of

the six limiting locations NUREG/CR-6260 evaluates, the pressurizer surge line is the only one

for which the CUF exceeded 1.0 when extrapolated to 60 years. However, the evaluations

contained in NUREG/CR-6260 use the interim fatigue curves published in NUREG/CR-5999,

which have been superseded by the fatigue curves reported in NUREG/CR-6717. Therefore,

the applicant must reevaluate the assessment of environmental effects for the limiting six

locations for ANO-2 using the fatigue life correction factors reported in NUREG/CR-6717,

Section 5.3. The limiting locations listed above should be evaluated for environmental effects in

accordance with the guidance provided in the GALL Report using the fatigue life correction

factors reported in NUREG/CR-6717, Section 5.3. The limiting vessel locations are made of

low-alloy steel, the safety injection and charging nozzles are made of carbon steel, and the

shutdown cooling system piping and pressurizer surge line piping are stainless steel. Using

NUREG/CR-6717, the bounding fatigue life correction factor for low-alloy steel, carbon steel,

and stainless steel are 2.5, 1.74, and 15.4, respectively.

The following summarizes the revised usage factors when including these environmental

correction factors:

* reactor vessel head-to-shell juncture (low-alloy steel) 0.0075

* reactor vessel outlet nozzle (low-alloy steel) 0.2223

* reactor vessel inlet nozzle (low-alloy steel) 0.347

* pressurizer surge line (stainless steel) 15.24

* charging nozzle (carbon steel) 1.357

* safety injection nozzle (carbon steel) 0.6534

* shutdown cooling line (stainless steel) 9.930

For the charging nozzle, shutdown cooling line piping, and pressurizer surge line piping, the

applicant would have to use more detailed stress analyses or fatigue monitoring and cycle

counting to reduce the CUF below 1.0. Because of the factor of safety included in the ASME

Code, a CUF greater than 1.0 does not indicate that fatigue cracking is expected. However,

there is a potential for fatigue cracking during the period of extended operation at locations

having CUFs exceeding 1.0. Therefore, before entering the period of extended operation, the

applicant will develop an approach for each location that may exceed a CUF of 1.0 when

considering environmental effects, in order to show that it can manage the effects of fatigue.

The approach for addressing environmental fatigue for the above locations will include one or

more of the following options:

* Further refine the fatigue analysis to lower the CUFs to below 1.0.

* Repair the affected locations.

* Replace the affected locations.

* Manage the effects of fatigue at the designated locations by an inspection program that

the NRC staff has reviewed and approved (e.g., periodic nondestructive examination of

the affected locations at inspection intervals to be determined by a method acceptable

to the NRC staff). The NRC staff expects that the inspections will be able to detect

cracking from thermal fatigue before the loss of function. The applicant will then

implement replacement or repair such that it will maintain the intended function for the

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period of extended operation.

* Monitor ASME Code activities to use the environmental fatigue methodology approved

by the Code committee and the NRC.

Should ANO-2 select option 4 (inspection) to manage environmentally assisted fatigue during

the period of extended operation, the applicant will provide details such as scope, qualification,

method, and frequency to the NRC staff for review and approval before entering the period of

extended operation. To obtain NRC staff approval of its proposed inspection plan to manage

fatigue prior to entering the period of extended operation for ANO-2, the applicant will submit a

license amendment request. After the NRC staff's approval of the inspection plan, any future

changes to the inspection plan will be evaluated in accordance with 10 CFR 50.59.

The applicant has evaluated the effects of environmentally assisted thermal fatigue for the,

limiting locations identified in NUREG/CR-6260 for ANO-2 in accordance with - 10 CFR 54.21 (c)(1)(i and ii),.and the NRC finds all locations acceptable for the period of

extended operation, with the exception of the charging nozzle, shutdown cooling line, and

pressurizer surge line. The applicant will address cracking of these locations by

environmentally assisted fatigue using one of the five approaches discussed above in

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

4.3.1.3.2 NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant

Systemse

In Section 4.3.3.2 of the LRA, the applicant addressed a concern identified in NRC Bulletin

88-08 regarding potential temperature stratification or temperature oscillations in unisolable

sections of piping attached to the RCS. Previously, Entergy had provided the NRC with the

responses required by Bulletin 88-08 and its supplements.

Based on the Entergy responses, the NRC staff found that ANO-2 meets the requirements of

NRC Bulletin 88-08. Commitments regarding inspections at ANO-2 in response to NRC Bulletin

88-08 have been superseded by the risk-informed inservice inspection (RI-ISI) of Class 1

piping, as approved by the NRC. Although the staff does not expect aging effects from thermal

stratification as described in Bulletin 88-08,'the applicant will confirm the absence of cracking

from thermal fatigue by inspections as part of the Inservice Inspection Program, in accordance

with 10 CFR 54.21(c)(1)(iii), during the period of extended operation.-;

4.3.1.3.3 NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification"

In Section 4.3.3.3 of the LRA, the applicant addressed pressurizer surge line thermal

stratification as an issue identified in NRC.Bulletin 88-11. The bulletin requires the applicant to

analyze the effects of this mechanism on the stress and fatigue calculations for the surge line.

Combustion Engineering (CE) performed a generic and bounding analysis for all CE plants and

submitted it to the NRC. To address this issue for the purposes of license renewal, the

applicant will include the pressurizer surge line bounding locations in the Fatigue Monitoring

Program. Therefore, the applicant will track realistic fatigue usage for the surge line and will

take actions to reevaluate, repair, or replace the surge line before a fatigue-induced failure

occurs. The applicant will manage the effects of aging in accordance with

10 CFR 54.21 (c)(1)(iii) for the period of extended operation.

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4.3.2 Staff Evaluation

4.3.2.1 Fatigue of ASME Class 1 Components

The staff has reviewed Section 4.3.1 of the LRA, in which the applicant addressed fatigue

evaluations of Class 1 components.

In RAI 4.3.1-1, the staff requested that the applicant list the editions of the ASME Code,

Section 1II, that apply to Class 1 fatigue analysis. The applicant provided these editions in its

response to the RAI, and the staff found them acceptable because they conform to the codes

listed in Table 3.2.4 of the ANO-2 SAR and to industry practice. In RAls 4.3.1-2 and 4.3.1-3,

the staff asked the applicant to indicate if it logged the number of transient cycles listed up to

July 11, 2002, in Table 4.3.1 of the LRA since the start of operation, and if the applicant logged

additional cycles since compiling the table. In its response, the applicant verified that it had

logged the cycles since the start of operation, and that it had recorded two reactor trips, one

cooldown cycle, and one heatup cycle, since July 11, 2002. This supported the applicant's

statement that the number of projected design cycles through the period of extended operation

will be well below the number of assumed design transient cycles. The staff finds the response

reasonable and in conformance with general experience at operating nuclear plants, and it

concurs with the applicant that the actual number of transient cycles under operating conditions

will be smaller that the number of assumed design cycles through the period of extended

operation.

On the basis of its review, the staff concludes that the applicant has provided an adequate

demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i), that the ANO-2 fatigue TLAAs for Class 1

components will remain valid for the period of extended operation.

Section A.2.2.2.1 of the LRA provides the applicant's supplement for the ANO-2 FSAR

regarding Class 1 metal fatigue. The staff reviewed this supplement and finds it provides an

adequate summary of the evaluation of Class 1 metal fatigue.

4.3.2.1.1 Conclusion

On the basis of its review, the staff concludes that the applicant has adequately demonstrated,

pursuant to 10 CFR 54.21 (c)(1), regarding fatigue TLAAs for ASME Class 1, that (1) some of

the analyses remain valid for the period of extended operation, (2) some of the analyses have

been projected to the end of the period of extended operation, or (3) it will adequately manage

the effects of aging on the intended function(s) for the period of extended operation.

The staff also concludes that the FSAR Supplement contains an adequate summary description

of ASME Code, Class 1 metal fatigue TLAAs evaluation for the period of extended operation, as

required by 10 CFR 54.21(d).

4.3.2.2 Fatigue of ASME Non-Class 1 Components

The staff has reviewed Section 4.3.2 of the LRA, in which the applicant addressed fatigue

evaluations of ASME non-Class 1 components.

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In RAI 4.3.2-1, the staff requested that the applicant provide the design codes that it used for

non-Class 1 fatigue analysis. In its reply, the applicant stated that non-Class I piping was,

designed to ANSI B31.1 or ASME Code, Section III, Classes 2 and 3. Non-Class .1 pressure

vessels, heat exchangers, storage tanks, and pumps were designed in accordance with ASME

Code, Section VIII, Division 1 or ASME Code, Section III, Classes 2 and 3. These codes

conform with those listed in Table 3.2-4 of the ANO-2 SAR and with industry practice, and are

therefore acceptable.

In RAI 4.3.2-2, the staff requested that the applicant provide the basis for the temperature

screening criteria of 104 'C (220 0F) for carbon steel and 132 0C (270 0F) for stainless steel. In

its response, the applicant stated that it based these criteria on industry-sponsored

investigations and evaluations of thermal fatigue in operating nuclear power plant piping,

systems, and components. The applicant also stated that these screening criteria are

consistent with the screening criteria given in Section 4.3.2 of the St. Lucie LRA. -The staff finds

that the applicant's 'screening criteria conform with industry practice and are therefore

acceptable.

4.3.2.2.1 Piping and In-Line Components

In RAI 4.3.2-3, the staff asked the applicant to clarify the revision of the RCS hot-leg sampling

piping calculation to justify RCS sampling at any reasonable frequency for 60 years of

operation, without exceeding the allowable number of cycles. In its response, the applicant

provided the requested justification. The staff has evaluated the response and finds it,

reasonable and acceptable, because it conforms with industry practice.

4.3.2.2.2 Pressure Vessels, Heat Exchangers, Storage Tanks, and Pumps

The applicant stated that it did not identified any non-Class 1 pressure vessels, heat

exchangers, storage tanks, or pumps that required evaluation for thermal fatigue. The staff -

finds this acceptable because it conforms to similar findings in previously accepted LRAs.

In RAI 3.3-1, the staff indicated that Tables 3.3.2-5 and 3.3.2-11 of the LRA identify fatiguecracking as an aging effect requiring management, but that Section 4.3.2 of the LRA does not

reflect this condition. The applicant credited inspections associated with the Periodic

Surveillance and Preventive Maintenance Program and system walkdowns with managing this

aging effect in the CVCS pump casing. The staff requested that the applicant clarify the type of

fatigue, managed by these inspections, thebasis for inspections in lieu of a TLAA for this

component, and the effectiveness of these inspections in detecting internal cracks before the

loss of intended function. In its response, the applicant stated that, regarding the CVCS

charging pump casing, it identified and managed cracking from high-cycle fatigue (as a result of

the deflection of the charging pump plunger cap during a pump cycle) as the aging effect. The

applicant discovered this cracking during plant operation and documented it in the Corrective

Action Program. The applicant stated that there is no requirement for an analysis involving

time-limited assumptions, and it found no such analysis for this condition during its identification

of TLAAs for license renewal. It is therefore outside the scope of Section 4.3.2 of the LRA.

However, the components listed in Table 3.3.2-1i1 of the LRA are generally nonsafety-related

but are designed in accordance with ANSI B31.1, which has an implicit limit of 7000 thermal

cycles. Cracking from thermal fatigue is generally not expected to occur, but the applicant

conservatively identified it as an aging effecfrequiring management. The applicant also stated

4-19
that, for the charging plunger cap, a preventive maintenance task exists to disassemble and

inspect the charging pumps and plungers. Operating experience has shown this inspection to

be effective in identifying the effects of aging before the loss of system function. For other

components, system walkdowns detect leakage and spray from liquid-filled systems.

On the basis of its review, the staff finds that the applicant has provided an adequate

demonstration, pursuant to 10 CFR 54.21 (c)(1), that the ANO-2 metal fatigue for ASME nonClass 1 components will remain valid for the period of extended operation, because it conforms

with industry operating practice.

Section A.2.2.2.2 of the LRA provides the applicant's supplement for the ANO-2 FSAR

regarding fatigue TLAAs of ASME non-Class 1 components. The staff has reviewed this

supplement and finds it provides an adequate summary of the evaluation of metal fatigue of

ASME non-Class 1 components at ANO-2, as required by 10 CFR 54.21 (d).

4.3.2.2.3 Conclusion

On the basis of its review, the staff concludes that the applicant has adequately demonstrated,

pursuant to 10 CFR 54.21 (c)(1), regarding fatigue TLAAs for ASME Class 1 and non-Class 1

components, that (1) some of the analyses remain valid for the period of extended operation,

(2) some of the analyses have been projected to the end of the period of extended operation, or

(3) it will adequately manage the effects of aging on the intended function(s) for the period of

extended operation.

The staff also concludes that the FSAR Supplement contains an adequate summary description

of ASME Class 1 and non-Class I metal fatigue TLAAs evaluation for the period of extended

operation, as required by 10 CFR 54.21 (d).

4.3.2.3 Response to Industry Experience

4.3.2.3.1 Effects of Reactor Coolant Environment on Fatigue Life of Components and Piping

(Generic Issue 190)

Generic Safety Issue (GSI)-1 66, "Adequacy of the Fatigue Life of Metal Components," raised

concerns regarding the conservatism of the fatigue curves used in the design of the RCS

components. Although' GSI-1 66 was resolved for the current 40-year design life of operating

components, the staff identified GSI-190, 'Fatigue Evaluation of Metal Components for 60-year

Plant Life," to address license renewal. The NRC closed GSI-190 in December, 1999,

concluding that: "The results of the probabilistic analyses, along with the sensitivity studies

performed, the iterations with industry (NEI and EPRI), and the different approaches available

to the licensees to manage the effects of aging, lead to the conclusion that no generic

regulatory action is required, and that GSI- 190 is closed. This conclusion is based primarily on

the negligible calculated increases in core damage frequency in going from 40 to 60 year lives.

However, the calculations supporting resolution of this issue, which included consideration of

environmental effects, and the nature of age-related degradation indicate the potential for an

increase in the frequency of pipe breaks as plants continue to operate. Thus, the staff

concludes that, consistent with existing requirements in 10 CFR 54.21, licensees should

address the effects of coolant environment on component fatigue life as aging management

programs are formulated in support of license renewal."

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In accordance with the staff position stated above, the applicant has evaluated the component

locations listed in NUREG/CR-6260 that are applicable to older Combustion Engineering plants

for the effect of the environment on the fatigue life of the corresponding components. For each

location, detailed environmental fatigue calculations were performed using the appropriate

correction factors reported in Section 5.3 of NUREG/CR 6717, "Environmental Effects on

Fatigue Crack Initiation in Piping and Pressure Vessel Steels," May 2001.

The limiting locations in NUREG-6260 were found to be acceptable for extended operation,%.

except for the charging nozzle, the shut down cooling line, and the pressurizer surge line. The

applicant has committed to manage the environmental fatigue effects at these locations during

the period of extended operations in accordance with the five options listed in Section 4.3.3.1 of

the LRA. The staff has reviewed these options-and finds them acceptable because the options

conform with the staff position on management of environmentally-assisted fatigue and were

previously found acceptable in other license applications.

Based on its review, the staff finds that the effects of environmental-assisted thermal fatigue for

the limiting locations identified in NUREG-6260 have been adequately evaluated for ANO-2, in

accordance with 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(ii), and that, with the exception

of the charging nozzle, shutdown cooling line, and pressurizer surge line, the remaining

locations are acceptable for the period of extended operation.

In accordance with 10 CFR 54.21 (c)(1), the staff 'also finds acceptable the applicant's

commitment to address potential cracking by environmentally-assisted fatigue at these

locations through the application of one of the five options discussed in Section 4.3.3.1 of the

LRA, because they have been found acceptable for other license renewal applications. Should

ANO-2 select the inspection option (Option 4) to manage environmentally-assisted fatigue,

details of the scope, qualification, method, and frequency of the inspection will be provide to the

NRC for review and approval prior to entering the period of extended operation.

In accordance with 10 CFR 54.21 (d), the applicant has included a section addressing the

effects of reactor coolant environment on fatigue life of components and piping (GSI-1 90) in the

ANO-2 FSAR Supplement Section A.2.2.2.3. ;-The staff finds this supplement provides a

adequate summary description of the information presented, and the commitments made, in

Section 4.3.3.1 of the LRA. ;-

4.3.2.3.2, NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant;..

Systems , - -I

The staff has reviewed Section 4.3.3.3 of the LRA, where the applicant addressed thermal

stresses in piping connected to reactor coolant systems as an issue identified in NRC Bulletin

88-08. The applicant stated that the Entergy commitments regarding inspections at ANO-2, in

response to NRC Bulletin 88-08, have been superseded by the risk-informed inspection (RI-ISI)

of ASME Class 1 piping, as approved by the NRC. Although aging effects due to thermal

stratification as described in Bulletin 88-08 are not expected, the absence of cracking due to

thermal fatigue will be confirmed by inspections as part of the inservice inspection program.

through the period of extended operation.

The staff finds the applicant's statements adequate because it conforms with the staff position

on thermal stratification, which forms part of the risk-informed inspection requirements of ASME

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Class 1 piping, and because the effects of aging associated with thermal stresses in piping

connected to reactor coolant systems will be managed, in accordance with 10 CFR 54.21 (c) (1)

(iii), for the period of extended operation.

The applicant's supplement to the ANO-2 FSAR regarding thermal stresses in piping connected

to reactor coolant systems is provided in Section A.2.2.2.4 of the LRA. The staff has reviewed

this supplement and finds it provides an adequate summary description of the metal fatigue

TLAA, as required by 10 CFR 54.21(d).

4.3.2.3.3 NRC Bulletin 88-11, Pressurizer Surge Line Thermal Stratification

The staff has reviewed Section 4.3.3.3 of the LRA, where the applicant addressed pressurizer

surge line thermal stratification as an issue identified in NRC Bulletin 88-11. The applicant has

addressed this issue for the purposes of license renewal, by committing to include the

pressurizer surge line bounding locations in the fatigue monitoring program. The applicant

stated that realistic fatigue usage for the surge line will be tracked, and actions will be taken to

reevaluate, repair, or replace the surge line before a fatigue-induced failure occurs. The staff

finds this acceptable because the effects of aging associated with pressurizer surge line

thermal stratification will be managed in accordance with 10 CFR 54.21 (c)(1)(iii) for the period

of extended operation.

The applicant's supplement to the ANO-2 FSAR regarding pressurizer surge line stratification

is provided in Section A.2.2.2.5 of the LRA. The staff has reviewed this supplement and finds it

provides an adequate summary description of the metal fatigue TLAA, as required by 10 CFR

54.21 (d).

4.3.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has adequately demonstrated,

pursuant to 10 CFR 54.21 (c)(1), that the TLAAs associated with specific industry experience

are acceptable in that the fatigue analyses for affected components: (i) remain valid for the

period of extended operation, or (ii) have been projected to the end of the period of extended

operation, or (iii) ensure that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

The staff also concludes that the FSAR Supplement contains an adequate summary description

of the responses to industry experience, as required by 10 CFR 54.21 (d).

4.3.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1), that metal fatigue TLAAs are adequate in that

the fatigue analyses: (i) remain valid for the period of extended operation, or (ii) have been

projected to the end of the period of extended operation, or (iii) the effects of aging on the

intended function(s) will be adequately managed for the period of extended operation.

The staff also concludes that Section A.2.2.2 of the FSAR Supplement contains an adequate

summary description of the metal fatigue TLAA evaluation for the period of extended operation,

as required by 10 CFR 54.21 (d).

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4.4 Environmental Qualification of Electrical Equipment

The NRC has identified the 10 CFR 50.49 Enviro'nmental Qualification Program as a TLAA for''

the purposes of license renewal. -The TLAA of environmental qualification (EQ) for electrical

components includes all long-lived, passive, and active electrical and instrumentation and

control components that are located in a harsh environment. The harsh environments are

those areas of the plant that are subjected to environmental effects by a loss-of-coolant

accident or high-energy line break (HELB) and that are important to safety. This equipment

consists of safety-related and Q-list equipment, nonsafety-related equipment whose failure'

could prevent satisfactory accomplishment of any safety-related function, and the necessary

postaccident monitoring equipment.

Pursuant to 10 CFR 54.21 (c)(1), an applicant must provide a list of EQ TLAAs in the LRA. The

applicant must demonstrate that one of the following is true for each piece of EQ equipment:

* The analyses remain valid for the period of extended operation.

* The analyses have been projected tothe end of the period of extended operation.

* The effect of aging on the intended function(s) will be adequately managed for the

period of extended operation.-,

The aging (or qualified life) analysis for electrical components involving time-limited

assumptions as defined by the current operating term for ANO-2 (i.e., 40 years), included as' -

part of the 10 CFR 50.49 Environmental Qualification Program, meets the 10 CFR 54.3

definition for a TLAA. The NRC thus considers the Environmental Qualification Program's

aging evaluation for electrical components a TLAA for license renewal.

As described in Section X.E1 of the GALL Report, the staff concludes that a plant's EQ

program, which implements the requirements of 10 CFR 50.49 (as further defined and clarified

by the DOR Guidelines, NUREG-0588, and RG 1 .89, Revision 1), meets the 1 0 program

attributes (or'elements) for an acceptable AMP as described in the GALL Report. A plant's EQ

program is therefore viewed as an acceptable AMP for license renewal.' -

An applicant performs a reanalysis of an aging evaluation in order to extend the qualification of

electrical components under 10 CFR 50.49(e) on a routine basis as part of a plant's EQ' ---

program. Important attributes for the reanalysis of an aging evaluation include analytical

methods, data collection and reduction methods,: underlying assumptions, acceptance criteria,

and corrective actions (if acceptance criteria are not met). Section X.E1 of the GALL Report

further discusses these attributes. ' ' *

The applicant may apply this reanalysis program to EQ components now qualified for the'

current operating term (i.e.,' those comporients now qualified for 40 years or more). The staff

has concluded, as'described in the Section X.E1 of the GALL Report, that a reanalysisprogram, which meets the conditions defined in the GALL Report for important attributes, is an

acceptable AMP for license renewal. Thus;'the NRC recommends no further evaluation for

license renewal if an applicant elects this option under 10 CFR 54.21 (c)(1)(iii).

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The staff reviewed Sections 4.4 and B.1.8 of the LRA to determine whether the applicant has

demonstrated that it will adequately manage the effects of aging on the intended function(s) of

electrical components through the ANO-2 EQ Program, together with other plant

programs/processes, during the period of extended operation as required by

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

4.4.1 Summary of Technical Information in the Application

.j

Sections 4.4 and B.1.8 of the LRA discuss the applicant's TLAA for electrical components. The

applicant stated that the ANO-2 Environmental Qualification Program is an existing program

established to meet ANO-2 commitments for 10 CFR 50.49. The Environmental Qualification

Program is consistent with Section X.E1 of the GALL Report.

The applicant concluded that continued implementation of the ANO-2 Environmental

Qualification Program provides reasonable assurance that the aging effects will be managed,

and that electrical components, within the scope of 10 CFR 50.49 requirements, will continue to

perform their intended function(s) for the period of extended operation. The ANO-2

Environmental Qualification Program will manage the effects of aging in accordance with the

requirements of 10 CFR 54.21 (c)(1)(iii).

Sections A.2.1.8 and A.2.2.3 of the LRA discuss the applicant's proposed FSAR Supplement

for the ANO-2 EQ Program. The applicant stated that the Environmental Qualification Program

manages component thermal, radiation, and cyclical aging of electrical equipment important to

safety as required by 10 CFR 50.49. The Environmental Qualification Program manages aging

effects through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods.

Aging evaluations for EQ components that specify a qualification of at least 40 years are

considered TLAAs for license renewal. The Environmental Qualification Program ensures that

the applicant will maintain the qualification of these EQ components. The applicant will thus

manage the effects of aging in accordance with 10 CFR 54.21 (c)(1)(iii).

The ANO-2 Environmental Qualification Program manages component thermal, radiation, and

cyclical aging, as applicable, through the use of aging evaluations based on 10 CFR 50.49(f)

qualification methods. As required by 10 CFR 50.49, the applicant must refurbish, replace, or

have the qualification of EQ components not qualified for the current license term extended

before reaching the aging limits established in the evaluation. The NRC considers aging

evaluations for EQ components that specify a qualification of at least 40 years to be a TLAA for

license renewal. The Environmental Qualification Program ensures the maintenance of these

EQ components in accordance with their qualification bases.

The ANO-2 Environmental Qualification Program is an existing program established to meet

ANO-2 commitments for 10 CFR 50.49. It is consistent with Section X.E1 of the GALL Report.

The ANO-2 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 after experiencing the effects of inservice aging. Consistent with NRC guidance

provided in RIS 2003-09, the NRC requires no additional information to address GSI-1 68, "EQ

of Electrical Components."

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Based upon a review of the existing program and associated operating experience, continued

implementation of the ANO-2 Environmental Qualification Program provides reasonable

assurance that the applicant will manage the aging effects and that the in-scope EQ

components will continue to perform their intended function(s) for the period of extended

operation. The ANO-2 Environmental Qualification Program will manage the effects of aging

will be managed in accordance with the requirements of 10 CFR 54.21 (c)(1 )(iii).

4.4.2 Staff Evaluation

The staff reviewed the information in Sections 4.4 and B.1.8 of the LRA to determine whether

the applicant has demonstrated that the effects of aging on the intended function(s) of electrical

components will be adequately managed through the ANO-2 Environmental Qualification

Program, together with other plant programs/processes, during the period of extended

operation as required by 10 CFR 54.21 (c)(1 )(iii). !Based on the applicant's statement that the

Environmental Qualification Program is consistent with Section X.EI of the GALL Report, the

staff concludes that the ANO-2 Environmental Qualification Program will adequately manage

the effects of aging on the intended function(s) of electrical components for the period of

extended operation in accordance with 1 O.CFR 54.21 (c)(1 )(iii).

Sections A.2.1.8 and A.2.2.3 of Appendix A to the LRA contain the applicant's FSAR -

Supplement for the Environmental Qualification Program as an AMP and TLAA for license

renewal. The staff reviewed this section and finds that the program description is consistent

with the material contained in Sections 4.4 and B.1.8 of the LRA. The staff finds that the FSAR

Supplement provides an adequate summary of the program activities as required by

10 CFR 54.21 (d).

4.4.3 Conclusions

The staff has reviewed the information in Sections 4.4 and B.1.8 of the LRA. On the basis of

this review, the staff concludes that the applicant has demonstrated that it will adequately

manage the effects of aging on the intended function(s) of electrical components that meet the

definition for TLAA as defined in 10 CFR 54.3 during the period of extended operation, as

required by 10 CFR 54.21 (c)(1 )(iii). In addition, the staff concluded, that the FSAR Supplement

contains an adequate summary description of the programs and activities for the evaluation of

TLAAs for the period of extended operation, as required by 10 CFR 54.21 (d).

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4.5 Concrete Containment Tendon Prestress

4.5.1 Summary of Technical Information in the Application

The applicant stated the mechanism it considered in developing the TLAA as follows:

Loss of prestress in the containment post-tensioning system is due to material

strain occurring under constant stress. The analysis of loss of prestress over the

initial 40-year license term is discussed in SAR Section 3.8.1.3.4, and is a timelimited aging analysis requiring review for license renewal. By assuming an

appropriate initial stress from tensile loading and using appropriate pre-stress

loss parameters, the magnitude of the design losses and the final effective

prestress at the end of 40 years for typical dome, vertical, and hoop tendons was

calculated at the time of initial licensing and following steam generator

replacement activities. A structural proof test was performed to verify the

adequacy of the containment building design.

Furthermore, the applicant stated that it will manage the loss of tendon prestress in the

containment building posttensioning system for license renewal through containment ISIs. The

containment ISI includes tendon surveillance testing. The ANO-2 tendon surveillance

procedures incorporate the requirements of ASME Code, Section Xl, Subsection IWL and

10 CFR 50.55(a).

Moreover, the applicant asserted the following:

Calculation of the effective prestress of the containment post-tensioning system

at 60 years has been performed and shows the containment tendons will be

acceptable for the period of extended operation. In addition, the Containment

Inservice Inspections will be adequate to manage the effects of aging on the

containment post-tensioning system for the period of extended operation.

Therefore, the applicant considers this TLAA acceptable in accordance with

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

4.5.2 Staff Evaluation

The applicant provided a description of the TLAA without providing any quantitative comparison

as to the present level of the prestressing forces based on the measured prestressing forces,

trend lines and projected forces during the extended period of operation. In order to understand

the basis for its assertions in Section 4.5.1 of this SER, the staff requested the following

information.

RAI 4.5-1

For the discussion of prestressing force losses over the initial 40 years, Section 4.5.1 of the

LRA refers to SAR Section 3.8.1.3.4 through a hypertext link. A review of SAR Section

3.8.1.3.4 indicates that it discusses the approach used in designing the containment to satisfy

the load combinations in SAR Section 3.8.1.3.3. It does not discuss the estimation of

prestressing forces at 40 years. The NRC requested the applicant to provide a reference to

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any other SAR Section which discusses the estimation of prestress force losses.

RAI 4.5-2

The use of 10 CFR 54.21 (c)(1 )(ii-iii) is appropriate for the concrete containmeit tendo'n

prestress TLAA. However, the staff must assess the plant-specific operating experience

regarding the' residual prestressing forces' in the containment. Based on the analysis performed

pursuant to 10 CFR 54.21 (c)(1 )(ii), the NRC requested the applicant to provide the following

information:

(a) minimum required prestressing forces for each'group of tendons

(b) '.'trend lines of the projected prestressing forces'for each group of tendons based on the

regression analysis of the measured prestressing forces (see NRC Information Notice

(IN) 99-10 for more information) :-

(c) plots showing comparisons of prestressing forces projected to 40 years and 60 years

with the minimum required prestress for each group of tendons

RAI 4.5-3

In Section A.2.2.4 of the FSAR -Supplement of the LRA, the applicant summarized the results of

its TLAA and stated the following:

Calculation of the acceptability of the effective prestress of the containment

building post-tensioning system at 60 years'has been performed to show th'at the

containment building tendon elements will be acceptable for the period of

extended operation in accordance with 10 CFR 54.21 (c)(1 )(ii).

By letter dated June 16, 2004, the applicant provided responses to these RAls, discussed

below. -- -

In response to RAI 4.5-1, the applicant provided the following values:

* loss from shrinkage and creep of concrete-"4200

* loss from relaxation of prestressing 'steekl-14.28 ksi for each group of tendons

The shrinkage and creep values (considering the sustained compressive stress of 1500 psi) is'

in the lower bound of the values suggested in RG 1'35.1. The steel relaxation value of 14.25

kilograms per square inch (ksi) (translates as'8 percent of the initial stress in the wires of the

tendons) is in the middle range of medium-relaxation prestressing steel. As a large deviation

from these values in the containment will show up in the non-normalized measured prestressinIg

forces, it is essential to have an accurate evaluation of the measured tendon forces for a

credible TLAA. For the purpose of estimating the minimum required prestressing forces in each

group of tendons, the staff considers these'values reasonable.

In response to RAI 4.5-2(a), the applicant provided the following minimum required prestressing

forces:

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* hoop tendons-1205.28 kips/tendon

* dome tendons-1233.18 kips/tendon

* vertical tendons-1370.82 kips/tendon

The staff finds these to be reasonable values for this type of containment.

In response to RAI 4.5-2 (b) and (c) dated June 16, 2004, the applicant explained that it had

started its random sampling program for ANO-2 containment in 1999. However, the applicant

provided the normalized prestressing force values of randomly selected tendons for each group

of tendons for ANO-1. A review of this data indicated that the process used for constructing

trend lines is not acceptable. In figures 1, 2, and 3, the applicant provided normalized wire

stress predictions based on two data points; (1) at 1 year after post-tensioning, and (2) at forty

years. The staff questioned the applicant determination of a data point at 40 years considering

the plant has been operating for less than 30 years. In addition, because of other irregularities,

the staff did not find the trend lines acceptable as a part of the TLAA. The staff requested a

supplemental clarification to the RAI:

RAI 4.5-2 (Clarification)

The responses to RAI 4.5-2 (b) and (c) indicated that prior to 1999 tendon inspection, the

applicant was not measuring the tendon forces in ANO-2. Thus, reliable data for constructing

trend lines was limited to only one set of readings. Under similar situation, two licensees

(applicants) have performed inspections of additional randomly selected tendons at

approximately two year interval. These augmented inspections were introduced to compensate

for the lack of reliable prestressing force data and to comply with the basic requirements of

Subsection IWL related to prestressing tendon force measurements, and 10 CFR

50.55a(b)(viii)(B). The trend lines shown in Figures 1, 2, and 3 could not be relied upon for

future projections. The applicant was requested to propose a plan or a program, that would

provide a valid TLAA for each group of tendons in ANO-2 containment. In developing the

program, the applicant was requested to follow the precautions and guidelines provided in NRC

Information Notice 99-10 [e.g., use of raw measured (non-normalized) prestressing forces, use

of tendon forces (instead of wire forces), trend line construction as provided in Attachment 3].

In the July 22, 2004 letter, the applicant stated its intention to perform the TLAA using

10 CFR 54.21 (c)(1)(iii). The option (iii) would allow the applicant to use an aging management

program for tracking the magnitudes of prestressing forces in ANO-2 containment. The staff

would accept the applicant's proposal, provided the applicant (1) addresses the ten elements of

the program (NUREG-1801 AMP X.S1) and (2) provides a description of the process that will

be used for developing prestressing force trend lines.

In the letter dated September 10, 2004, the applicant provided the following information:

Consistent with 10 CFR 54.21 (c)(1)(iii), loss of tendon prestress will be

adequately managed during the period of extended operation by continued

implementation of tendon inspections required by ASME Code Section Xl IWL.

Relevant operating experience, including experience with prestressing systems

described in NRC Information Notice (IN) 99-10, will be considered during

inspections and data analysis. Prior to the period of extended operation, trend

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lines for ANO-2 tendon prestressing forces will be developed using regression

analysis in accordance with guidance provided in NRC Information Notice (IN)

99-10. If future tendon examination data diverge from the expected trend, the

discrepancy will be addressed in accordance with requirements of the

Containment Inservice Inspection (ISI) Program (IWEIIWL) and the current

licensing basis. Specifically, if prestressing force trend lines indicate that existing

prestressing forces in the containment would go below the minimum required

values (MRVs) prior to the next scheduled inspection (Reference 10 CFR

50.55a(b)(2)(ix)(B) or 10 CFR 50.55a(b)(2)(viii)(B)), then systematic retensioning

of tendons, a reanalysis of the containment or a reanalysis of the post-tensioning

system is warranted to ensure the design adequacy of the containment.

In summary, the ANO-2 Containment ISI Program in accordance with the requirements

of ASME Code Section Xl IWL will provide reasonable assurance that the effects of

aging on the intended functions of tendons will be adequately managed for the period of

extended operation in accordance with the provisions of 10 CFR 54.21 (c)(1 )(iii).

The staff finds the response acceptable as it essentially provides all information that would be

provided in X.S1 of NUREG-1801 for aging management of containment prestressing tendon

forces. Moreover, Attachment 2 of the letter provides a commitment that the applicant will

perform its TLAA based on the measured prestressing forces during the subsequent tendon

inspections.

In response to RAI 4.5-3, the applicant stated;

ANO-2's containment inservice inspection program (Section B.1.13), in accordance with

ASME Section Xl, delineates the required documentation and the acceptance criteria for

the prestress forces applicable for the period of extended operation. The validity of the

prestress analysis, per ASME Section Xl, subsection IWL is demonstrated in site

documents. The adequacy of the aging management program (i.e., IWL) is assured

since, as described in Section B.1.13 of the LRA, the program is consistent with the

NUREG-1801 program and with current regulatory requirements. In accordance with

the Statements of Consideration for the license renewal rule, 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. Therefore, a summary table showing

minimum required prestress forces for each group of tendons is not warranted in the

SAR.

As discussed above, the applicant's statement in Section A.2.2.4 of the LRA, "Calculation of the

acceptability of the effective prestress of the containment building post-tensioning system at 60

years has been performed to show that the containment building tendon elements will be

acceptable for the period of extended operation in accordance with 54.21 (c)(1 )(ii)," is not

correct, and should be modified to reflect the resolution of RAI 4.2-5. The applicant was

requested to provide the revised Section A.2.2.4.

In the letter dated September 10, 2004, the applicant provided a revision to LRA section A.2.2.4

as follows:

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A.2.2.4 CONCRETE CONTAINMENT TENDON PRESTRESS

The analysis of loss of prestress in the containment building post-tensioning system is a

time-limited aging analysis. Loss of tendon prestress in the containment building post

tensioning system will be managed for license renewal in accordance with 1 0 CFR

54.21 (c)(1 )(iii), by the Containment ISI Program. This program, discussed in Section

A.2.1.14, includes tendon surveillance testing. Prior to the period of extended operation,

trend lines for ANO-2 tendon prestressing forces will be developed using regression

analysis in accordance with guidance provided in NRC IN 99-10. If prestressing force

trend lines indicate that existing prestressing forces in the containment would go below

the minimum required values (MRVs) prior to the next scheduled inspection (Reference

10 CFR 50.55a(b)(2)(ix)(B) or 10 CFR 50.55a(b)(2)(viii)(B)), then systematic

retensioning of tendons, a reanalysis of the containment or a reanalysis of the post

tensioning system is warranted to ensure the design adequacy of containment.

The staff finds the revision to LRA Section A.2.2.4 acceptable, as it provides an acceptable

summary of the TLAA.

4.5.3 Conclusions

On the basis of the review of this section of the LRA, the staff concludes that the applicant's

plans to perform TLAAs in accordance with 10 CFR 54.21 (c)(1 )(iii) is acceptable. As the

applicant will adjust the trend lines based on the results of future tendon inspections, pursuant

to 10 CFR 54.21 (c)(1 )(iii), the AMP implemented using the described process will ensure the

adequacy of prestressing forces in the ANO-2 containment.

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4.6 Containment Liner Plate and Penetration Fatique Analyses

4.6.1 Summary of Technical Information in the Application

The applicant stated in Section 4.6 of the LRA that the interior surface of the containment is

lined with welded carbon steel plate to provide an essentially leak-tight barrier.- At the -

penetrations, the containment liner plate is thickened to reduce stress concentrations. The

criteria in SAR Sections 3.8.1.3.4 and 3.81.6.3 were applied to the containment design to

ensure that the integrity of the liner plate is not exceeded under design-basis accident (DBA)

conditions. The applicant's evaluation of this issue for license renewal is based on an analytical

assessment of the containment liner and penetrations as described in SAR Section 3.8.1.4.2,

as well as on the results of recently completed containment liner plate evaluations for ANO-2.

The TLAAs for the ANO-2 reactor containment structure include containment liner and

containment penetration fatigue analyses. Mechanical penetrations are leak-tight, welded

assemblies. As described in SAR Section 3.8.1.4.2, containment penetrations are designed to

meet the requirements of ASME Code, Section IlIl.

The evaluation for mechanical penetrations covers the penetration assembly and the weld to

the process piping, but does not include the process piping within the penetration. The closure

of the pipe to the liner plate is accomplished with special heads welded to the pipe and the liner

plate reinforcement. Penetration anchorage to the containment wall is designed to resist pipe

rupture, seismic loads, and thermal loads.

The liner plate stress analyses indicate a conservative maximum stress of approximately 30 ksi

for worst case (i.e., DBA) conditions. Stresses from normal operating cycles such as heatup

and cooldown are less than 30 ksi. Using the ASME Code, Section 1I1, Division 1 design fatigue

curve, at 30 ksi the maximum cycles for the liner would be approximately 25,000. The number

of normal operating cycles for the liner plate is projected to be well below this value. Therefore,

the liner plate and penetrations are suitable for the cyclic loads of normal operating conditions

throughout the period of extended operation. On this basis, the applicant concluded that the

containment liner plate and penetration fatigue analyses remain valid for the period of extended

operation, in accordance with 10 CFR 54.21 (c)(1 )(i).

4.6.2 Staff Evaluation

In RAI 4.6-1, the staff asked the applicant to provide the loading conditions and corresponding

transient cycles used in the fatigue analysis of the containment liner plate and penetrations. In

its response, the applicant clarified that it provided the loading conditions in Section 3.8.1.3 of

the SAR. The applicant also stated that it did not explicitly address fatigue in the containment

analysis because the calculated peak stress intensities resulted in allowable fatigue cycles,

which far exceed the projected number of anticipated cycles for all operating conditions. In RAI

4.6-2, the staff requested that the applicant provide the ASME Code, Section III, CUFs and

locations from the recently completed containment liner plate and containment penetration

fatigue analyses, showing that these fatigue TLAAs will remain valid for the period of extended

operation. In its reply, the applicant stated that, in accordance with its response to RAI 4.6-1, it

did not determine ASME Code, Section IlIl, CUFs because the allowable fatigue cycles far

exceed the projected number of anticipated cycles for all operating conditions. These cycles

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were listed as 60 annual outdoor temperature variations, 500 cycles of reactor building interior

temperature variation, and 1 thermal cycle because of a postulated DBA. The staff finds these

responses reasonable and adequate because they correspond with similar results evaluated

and accepted by the staff in previous LRA reviews.

4.6.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i), that, based on fatigue TLAAs for the

containment liner plate and penetration, the analyses remain valid for the period of extended

operation.

The staff also concludes that Section A.2.2.5 of the FSAR Supplement contains an adequate

summary description of the containment liner plate and the penetrations fatigue TLAA

evaluation for the period of extended operation, as required by 10 CFR 54.21 (d).

4-32
4.7 Other Plant-Specific Time-Limited Ajing Analyses

Other potential plant-specific TLAAs include leak before break (LBB) analyses, fracture

mechanics evaluation of the RCP casing and flywheel, steam generator flow-induced vibration

(FIV) analysis, qualification analyses of Alloy 600 nozzle repairs, and HELB analyses.

4.7.1 Reactor Coolant System Piping Leak Before Break Analysis

4.7.1.1 Summary of Technical Information in the Application

The NRC modified 10 CFR Part 50 General Design Criterion (GDC) 4, Environmental and

Missile Design Bases," in 1987. This change allows licensees to disregard the dynamic effects

of postulated ruptures in primary coolant loop piping in the design of PWRs if LBB criteria are

met. In 1990, an LBB analysis-(Topical Report CEN-367-A) was performed for CE-designed

nuclear steam supply systems (Reference 4.7-1). This analysis demonstrated that plant

monitoring systems can detect potential leaks in the RCS primary loop piping before a

postulated crack causing the leak would grow to unstable proportions during the 40-year plant

life. The NRC approved this analysis in its safety evaluation (SE) dated 'October 30, 1990

'(Reference 4.7-5). The original design basis for the ANO-2 RCS considered postulated breaks

for the purposes of evaluating protection from the dynamic and 'environmental effects of the

main coolant line (MCL) breaks. The charnges to'GDC 4 allowed the application of LBB criteria

for the' selection of MCL breaks. The NRC approved the criteria for use at ANO-2 through its

SE dated June 18,' 1996 (Reference 4.7-2).: This application of LBB has eliminated the

requirement to consider postulated breaks on the MCL in evaluating the dynamic effects on the

RCS. The original LBB analysis was updated for the steam generator replacement and power

uprate to demonstrate that conclusions of the original analysis remain valid.

The analysis consideration that could be time-limited is the accumulation of fatigue transient

cycles over time, which could invalidate the fatigue crack growth analysis reported in CEN-367-

A, Section 3.0. The crack growth rate laws were evaluated for the fatigue transients presented

in Table 3-1 of CEN-367-A. Section 4.3.1 of this SER reviews the ANO-2 fatigue transient cycle

definitions, demonstrating the Fatigue Monitoring'Program to be capable of'monitorin'g the '

Class 1 -thermal fatigue design-basis transients for the period of extended operation, including'

the transient assumptions reported in CEN-367-A'

A review of CEN-367-A identified the fatigue crack growth analysis'as a TLAA. Continued

implementation of the ANO-2 Fatigue Monitoring Program provides reasonable assurance that"

the fatigue crack growth analysis reported in CEN-367-A will remain valid during'the'period of

extended operation. The LBB TLAA remains valid for the period of extended operation in

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

The applicant described its LBB analysis for the RCS in Section 4.7.1 of the LRA.- The staff

reviewed this section to determine if the applicant provided adequate information to meet the'

requirements contained in 10 CFR 54.21 (c),' related to the TLAA for LBB.

In CEN-367-A, Revision 000, "Leak-Before-Break Evaluation of Primary Coolant Loop Piping-in'

Combustion Engineering Designed Nuclear Steam Supply Systems," CE describes a successful

application of LBB to the RCS primary loop piping.2 This report provides the technical basis for

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evaluating two distinct postulated flaws in the RCS main-loop piping as an essential element of

the LBB methodology, (1) the determination of the leakage flaw size under the normal loading

condition and (2) the determination of the allowable critical flaw size under the faulted loading

condition.

The applicant stated that the LBB analysis considered the accumulation of actual fatigue

transient cycles over the period of extended operation that could invalidate the fatigue flaw

growth analysis performed as part of the original LBB analysis. The applicant reviewed the

accumulation of the applicable fatigue transient cycles to meet the TLAA definition. The

applicant completed this review within the scope of the Fatigue Monitoring Program that it

implemented at ANO-2. The applicant stated that the continued implementation of the Fatigue

Monitoring Program provides reasonable assurance that the fatigue crack growth analysis

reported in CEN-367-A will remain valid during the period of extended operation. The LRA

concludes that the LBB TLAA remains valid in accordance with 10 CFR 54.21 (c)(1)(i).

4.7.1.2 Staff Evaluation

In RAI-4.7.1-1, the staff asked the applicant to discuss its basis and conclusions regarding the

additional crack growth predicted by the updated calculations for the end of 60 years compared

to that originally predicted for 40 years. The staff confirmed that the NRC generically approved

the LBB applications for the primary loop piping for Combustion Engineering Owners Group

(CEOG) plants on October 30, 1990, and specifically for ANO-2 on June 18, 1996. The CEOG

provides this generic LBB evaluation in CEN-367-A. There are two time-limited considerations

for LBB analysis, crack growth and thermal aging. The material properties of cast austenitic

stainless steel (CASS) can change over time. Thermal aging causes an elevation in the yield

strength of the material and a degradation of the fracture toughness, with the degree of

degradation being a function of the level of ferrite in the material. Thermal aging in CASS will

continue until a saturated or fully aged point is reached.

In response to RAI-4.7.1 -1, the applicant stated that the LBB fatigue crack growth analysis

reported in CEN-367-A is based on 40- year design limits for RCS fatigue transient cycles. In

CEN-367-A, the applicant performed fatigue crack growth to show that fatigue will not cause

degradation of the pressure boundary integrity. In the fatigue crack growth analysis, the normal

and upset cyclical loadings cause postulated flaws to grow. These cyclical loadings are based

on reactor coolant design transient cycles. As described in Section 4.3.1 of the LRA, the

number of transient cycles assumed in the original design for 40 years was found acceptable

for 60 years of operation. Therefore, the postulated flaw growth in CEN-367-A (based on the

RCS original design transient cycles) is unchanged for 60 years of operation. The staff finds

the response acceptable and considers this issue closed.

The assessment in CEN-367-A uses the fracture toughness values of the

SA-515 Grade 70 carbon steel weld in the LBB analysis, which are the lowest among all base

and weld materials in the primary loop piping system. The staff has compared the fracture

toughness values in CEN-367-A with the more recent information in

NUREG-6177, "Assessment of Thermal Embrittlement of Cast Stainless Steels," and found that

the fracture toughness data in CEN-367-A data are more conservative than the NUREG-6177

lower-bound fracture toughness curve. Therefore, because the original analysis supporting

LBB bounds fully aged CASS, the analysis does not have a material property time dependency

that requires further evaluation for license renewal.

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For the primary loop piping, instead of revising the original analyses by taking into account the

fatigue transient cycles for the period of extended operation, the applicant relied on the plantspecific Fatigue Management Program to ensure that the accumulation of the applicable fatigue

transient cycles over time will not invalidate the fatigue flaw growth analysis that it performed as

part of the original LBB analyses. With this program in place; which calls for constant review of

the accumulation of applicable fatigue transient cycles, the applicant concluded that the

continued implementation of the Fatigue Management Program will provide reasonable

assurance that the RCS components within the scope of license renewal will continue to

perform their intended function(s) consistent with the CLB for the period of extended operation.

The staff reviewed the Fatigue Management Program and determined that the program is

adequate to monitor the applicable set of transients and their limits, and to count the actual

thermal cycle transients to ensure that it is within the allowable limits of the defined transients.

In the event that design cycle limits are approached, the applicant will review the Fatigue

Management Program and determine appropriate actions.

Based on the above evaluation, the staff agrees with the applicant's conclusion that the

continued implementation of the Fatigue Management Program provides reasonable assurance

that it will manage thermal fatigue for the primary loop piping and components, and therefore

the analyses for this TLAA remain valid for the period of extended operation, in accordance with

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

Since the V.C. Summer main coolant loop weld cracking event involving Alloy 82/182 weld

material, the staff has considered the effect of primary water stress-corrosion cracking on Alloy

82/182 piping welds as an operating plant issue affecting all piping with or without approved

LBB applications. To resolve this issue, the industry has taken the initiative to (1) develop

overall inspection and evaluation guidance, (2) assess the current inspection technology, and

(3) assess the current repair and mitigation technology. An interim industry report, "PWR

Materials Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plants (MRP-44),

Part 1: Alloy 82/182. Pipe Butt Welds," was published in April 2001 to justify the continued

operation of PWRs while the industry completes the development of the final report. The staff

accepted this interim report in an SE dated June 14, 2001, stating that, "Should the industry not

be timely in resolving inspection capabilities to identify PWSCC in Alloy 600 welds, regulatory

action may result." Little has been accomplished in the interim and the staff is pursuing further

regulatory action.

4.7.1.3 FSAR Supplement

Section A.2.2.6.1 of Appendix A to the LRA provides the applicant's FSAR Supplement

regarding LBB for RCS piping. The plant design cycles in the applicant's LBB analysis are

consistent with those used in the fatigue crack growth analysis, and they bound the period of

extended operation. In addition, the applicant's appropriate consideration of thermal aging of

the CASS material constitutes the basis for-the staff's acceptance of the licensee's evaluation

of the LBB TLAA for the period of extended operation. On the basis of its review of the FSAR

Supplements, the staff concludes that the summary description of the applicant's TLAA

evaluation to address LBB for the period of extended operation is adequate and satisfies 10

CFR 54.21 (d).,

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4.7.1.4 Conclusions

The staff concludes that, pursuant to 10 CFR 54.21 (c)(1)(i), the applicant has provided an

acceptable demonstration that, for the TLAA on LBB of the RCS main-loop piping, the analysis

will remain valid for the period of extended operation, and the applicant will adequately manage

the effects of aging on the pressure boundary function for the period of extended operation.

The staff also concludes that the FSAR Supplements contain an adequate summary description

of the evaluation of the TLAA for LBB, as required by 10 CFR 54.21 (d).

4.7.2 Reactor Coolant Pump Code Case N-481

4.7.2.1 Summaty of Technical Information in the Application

In Section 4.7.2 of the ANO-2 LRA, the applicant described an analysis based on ASME Code

Case N-481 for alternative inspection criteria for RCP casings. The staff reviewed this section

to determine whether the applicant provided adequate information to meet the requirements

contained in 10 CFR 54.21 (c) related to the TLAA for the RCP casings, as based on the criteria

of ASME Code Case N-481.

The two analysis considerations of concern to the TLAA identified in the LRA are (1) loss of

fracture toughness of the pump casing's CASS material of the because of thermal aging and

(2) the accumulation of actual fatigue transient cycles over time that could invalidate the fatigue

crack growth analysis of the ANO-2 ASME Code Case N-481 evaluation.

Because the ASME Code Case N-481 analysis assumes fully aged (saturated) properties, the

LRA concludes that the TLAA needs no further evaluation for license renewal to address

concerns with material property changes. The LRA describes' a review of the accumulation of.

the applicable fatigue transient cycles that the applicant performed to meet the TLAA definition.

The applicant performed this review within the scope of the Fatigue Monitoring Program that it

implemented at ANO-2. The applicant stated that the continued'implementation of the FMP

provides reasonable assurance that the fatigue crack growth analysis will rermiain valid during

the period of extended operation. The LRA concludes that the TLAA will remain valid in

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

The applicant evaluated a demonstration of compliance of the primary loop pump casings to

ASME Code Case N-481 for ANO-2. This analysis considers thermal aging of the CASS pump

casings and fatigue crack growth. Because these evaluations could be influenced by time, the

Code Case N-481 analysis is a potential TLAA.

The first analysis consideration that could be time limited is the material properties of CASS.

Such steels used in the RCS are subject to thermal aging during service. Since the Code Case

N-481 analysis relied on fully aged (saturated) stainless steel material properties, the analysis

does not have a material property time dependency that requires further evaluation for license

renewal.

In addition, the accumulation of actual fatigue transient cycles over time could invalidate the

fatigue crack growth analysis of the ANO-2 Code Case N-481 evaluation. Section 4.3.1 of this

SER discusses a review of the ANO-2 fatigue transient cycle definitions, demonstrating that the

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Fatigue Monitoring Program adequately monitors thermal fatigue design transients, including

the transient cycle assumptions reported in the ANO-2 Code Case N-481 evaluation, for the,

period of extended operation. The continued implementation of the Fatigue Monitoring

Program provides reasonable assurance that the ANO-2 Code case N-481 fatigue crack growth

analysis will remain valid during the period of extended operation, in accordance with

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

4.7.2.2 Staff Evaluation

There are two time-limited considerations for the ASME Code Case N-481 analysis. First, the

material properties of CASS can change over time. -Thermal aging of the pump casing material

causes an elevation in the yield strength material and a degradation of the fracture toughness,

with the degree of degradation being a function of the level of ferrite in the material. Thermal

aging in CASS will continue until a saturated or fully.aged point is reached. The applicant used

fully aged (saturated) properties in its analysis and concluded that it addressed the effects of

thermal aging on material properties of the CASS RCP casings for the period of extended

operation. In RAI 4.7.2-1, the staff asked the applicant to discuss whether the properties

considered in the analysis are the same bounding properties that it used for fully aged CASS

materials, as assumed in CEN-367-A. If the applicant considered other material properties for

the ASME Code Case N-481 analysis, the staff asked the applicant to justify its use of those

properties.

In response to RAI 4.7.2-1, the applicant stated that, because of the variety of materials used at

the different plants, it used bounding values from participating plants in CEN-367-A for the

material properties for stainless steel safe ends. In contrast, the applicant completed the ASME

Code Case N-481 evaluation specifically for ANO-2, and thus used ANO-2 specific material

properties for the RCP casings. The staff finds the response acceptable and considers this

issue closed.

The applicant performed a qualitative assessment in order to show that the plant-specific

Fatigue Monitoring Program can programmatically manage the assumptions, including the

fatigue cycles, in the existing analyses for the period of extended operation. In RAI-4.7.2-2, the

staff asked the applicant to discuss, the additional crack growth that the updated calculations

predicted for the end of 60 years and compare the crack growth to that originally predicted for

40 years. The staff also asked the applicant to provide the criteria or basis for concluding that

this amount of additional crack growth is sufficiently small to justify continued application of

ASME Code Case N-481.

In response to RAI-4.7.2-2, the applicant stated that it did not update the ASME Code Case

N-481 calculation for 60 years. As described in Section 4.7.2 of the ANO-2 LRA, the ASME

Code Case N-481 analysis remains valid forthe period of extended operation in accordance

with 10 CFR 54.21 (c)(1)(i).. In the ASME CodeCase N-481 evaluation, the applicant

determined fatigue crack growth in order to assure that fatigue will not cause degradation of

pressure boundary integrity.. In the fatigue crack growth analysis, the normal and upset cyclical

loadings cause postulated flaws to grow. These cyclical loadings are based on RCS design

transient cycles. As described in Section 4.3.1 of the LRA, the number of transient cycles

assumed in the original design for 40 yearswas found acceptable for 60 years of operation

(i.e., the number of transients, used for 40 years of operation are still bounding for 60 years of

operation). Therefore, the postulated flaw has no additional crack growth when extending the

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period of operation to 60 years. The staff finds the response acceptable and considers this

issue closed.

4.7.2.3 FSAR Supplement

Section A.2.2.6.2 of Appendix A to the LRA provides the applicant's FSAR Supplement

summary description for the TLAA on the RCP casings, as performed in accordance with the

ASME Code Case N-481 criteria. The plant design cycles considered in the applicant's

analysis are consistent with those it used in the fatigue crack growth analysis and bound the

period of extended operation. In addition, the applicant's appropriate consideration of thermal

aging of the CASS material constitutes the basis for the staff acceptance of the licensee's

evaluation of the TLAA for the period of extended operation. On the basis of its review of the

FSAR Supplements, the staff concludes that the summary description of the applicant's TLAA

evaluations to address the ASME Code Case N-481 evaluation for the period of extended

operation is adequate and satisfies 10 CFR 54.21 (d).

4.7.2.4 Conclusions

The staff concludes that, pursuant to the acceptability criteria of 10 CFR 54.21 (c)(1)(i), the

applicant has provided an acceptable demonstration that, for the TLAA on the RCP casings, as

performed in accordance with the ASME Code Case N-481 criteria, the analysis will remain

valid for the period of extended operation for ANO-2, and the applicant will adequately manage

the effects of aging on the pressure boundary function for the period of extended operation.

The staff also concludes that the FSAR Supplement contains an adequate summary description

of the TLAA evaluation for the RCP casings, as required by 10 CFR 54.21 (d).

4.7.3 Reactor Coolant Pump Flywheel

4.7.3.1 Summary of Technical Information in the Application

In Section 4.7.3 of the ANO-2 LRA, the'applicant describes an analysis of fatigue crack

initiation and growth for the RCP flywheel. The staff reviewed this section to determine whether

the applicant provided adequate information to meet the requirements of 10 CFR 54.21 (c)(1),

as the information relates to the TLAA for the RCP flywheel.

To reduce the RCP flywheel inspection frequency and scope, ANO-2 submitted a topical report

in 1995 that uses a fatigue crack growth calculation to evaluate the effects of cyclic stresses

and fatigue. The NRC staff reviewed and approved the topical report on May 21, 1997. Crack

growth calculations were based on an assumed 4,000 cycles of RCP startups and shutdowns

rather than a specific time period of operation. The LRA states that the number of cycles from

actual plant operating conditions through the end of the extended period of operation will be

much less than the assumed 4,000 cycles. On this basis, the applicant originally concluded

that the analysis of the 1995 topical report applies to the extended period of plant operation,

and that the flywheel analysis is not a time-limited analysis from the standpoint of the license

renewal application.

In the applicant's response to RAI 4.7.3-1, dated September 10, 2004 (Entergy Letter No.

2CAN090402), the applicant modified its position and stated that it will treat the low-cycle

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fatigue crack growth analysis for ANO-2 RCP flywheels as a TLAA for the ANO-2 LRA.

4.7.3.2 Staff Evaluation

In the ANO-2 LRA, the applicant concluded that the RCP flywheel is not a TLAA. The basis for

this conclusion is a 1997 safety evaluation of a fatigue crack growth analysis that was

presented in a Combustion Engineering Owner's Group topical report. This safety evaluation

allowed the licensee to lengthen the RCP flywheel inspection period for ANO, Units I and 2 and

five other units. The fatigue crack growth analysis for ANO, -Units 1 and 2 is based on 4,000

RCP startup and shutdown cycles. Table 4.1-3 of the NUREG-1 800, Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants, identifies that low-cycle

fatigue crack growth analyses for PWR RCP flywheels are TLAAs for PWR-designed lightwater reactors. In RAI 4.7.3-1, the staff requested that the applicant provide the TLAA for the

RCP Flywheel for ANO Unit 2, and include the justification for why 4,000.RCP startup and

shutdown cycles remain bounding through the end of the extended period of operation for

ANO-2.

In the applicant's response to RAI 4.7.3-1 ,dated September 10, 2004, the applicant has states

that it will treat the low-cycle fatigue crack growth analysis for ANO-2 RCP flywheels as a TLAA

for the ANO-2 LRA and that the 4000 plant startup/shutdown cycles assumed in the crack

growth analysis remain bounding for the number of plant startup/shutdown cycles (RCP : - start/trip cycles) assumed for the facility through both 40 years and 60 years of licensed (500

plant startup/shutdown cycles is assumed in design basis for both the current operating term

and extended operating term). The applicant concluded that the the low-cycle fatigue crack

growth analysis for the RCP flywheels meets the TLAA analysis acceptability criteria of 1 0 CFR

54.21 (c)(1 )(i).

Section 5.2.6 of the ANO-2 FSAR provides the design basis for how the applicant's design,

fabrication, testing, inspection, and analysis program for the RCP flywheels is designed to

conform to staff's design, fabrication, testing, inspection, and analysis criteria that are

recommended in NRC Regulatory Guide 1.14, Revision 1, Reactor Coolant Pump Flywheel

Integrity (August 1975). Subsection 5.2.6.2 to Section 5.2.6 of the ANO-2 FSAR indicates that

a 1.0 inch deep crack is assumed to occur in the keyway of the limiting flywheel disc and that

the critical crack size for the flywheel is 1.8 inches.-The low-cycle fatigue crack growth analysis

for the RCP flywheels demonstrates that the postulated flaw in the analysis will not grow in

excess of the critical crack size for the flywheel disc, even when the flywheels have been

subjected to the change in the stress intensity factor for the flywheel discs associated with 4000

RCP startup/shutdown cycles. Since this bounds the number of RCP startups/shutdown cycles

assumed for both the current operating period and the proposed period of extended operation,

the staff concludes that the low-cycle fatigue crack growth analysis for the RCP flywheels

meets the acceptance criterion for TLAAs in 10 CFR 54.21 (c)(1)(i), in that the analysis remains

bounding for the period of extended operation. -.- - --

4.7.3.3 FSAR Supplement

Appendix A of the applicant's FSAR supplement does not address the fatigue analysis for the

reactor coolant pump flywheel. The LRA states that the existing analysis of the 1995 topical

report does not involve time limiting assumptions which would restrict application to only the

current operating term or preclude application to the extended period of plant operation. The

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staff concluded that the fatigue analysis for the reactor coolant pump flywheel is a TLAA, and

that the applicant should submit the TLAA for staff evaluation. In the applicant's response to

RAI 4.7.3-1, dated September 10, 2004, the applicant stated that it will treat the low-cycle

fatigue crack growth analysis for ANO-2 RCP flywheels as a TLAA for the ANO-2 LRA. The

applicant provided the following FSAR Supplement summary description (i.e., Section A.2.2.6.6,

RCP Motor Flywheel, of Appendix A to the ANO-2 LRA) for the TLAA on the TLAA on the lowcycle fatigue crack growth analysis for the RCP flywheels.

A.2.2.6.6 RCP Motor Flywheel

The flaw growth analysis associated with the reactor coolant pump motor flywheel is

conservatively treated as a time-limited aging analysis. The analysis addresses the

growth of pre-existing cracks subjected to 4,000 reactor coolant pump motor startup or

shutdown cycles, which exceeds by a factor of eight the number of RCP cycles

projected through the period of extended operation. Therefore, the flaw growth analysis

remains valid for the period of extended operation.

The applicant's FSAR Supplement summary description provides a summary description basis

for the low-cycle fatigue crack growth analysis that is consistent with the staff's evaluation that

is discussed in Section 4.7.3.2 of this SER. The FSAR Supplement summary description for

the TLAA on the RCP Motor Flywheel is therefore acceptable to the staff, and satisfies the

criterion for FSAR Supplement summary descriptions in 10 CFR 54.21 (d). Section 5.2.6 of the

ANO-2 FSAR provides additional details and information on the applicant's inspection programs

and structural integrity analyses for the RCP flywheels, as implemented in conformance with

the NRC's recommended guidelines in Regulatory Guide 1.14, Revision 1, Reactor Coolant

Pump Flywheel Integrity (August 1975).

4.7.3.4 Conclusions

The staff concludes that the applicant has provided an acceptable demonstration pursuant to

10 CFR 54.21 (c)(1)(i) that, for the TLAA on the RCP motor flywheel, the analysis remains valid

for the period of extended operation.

The staff also concludes that the FSAR supplements contain an adequate summary description

of this TLAA evaluation for the period of extended operation, as required by 10 CFR 54.21 (d).

4.7.4 Steam Generator Tubes-Flow-Induced Vibration

4.7.4.1 Summary of Technical Information in the Application

TLAAs applicable to the steam generators include analyses of steam generator tube FIV. The

ANO-2 steam generator design life extends to 2040, as they were installed in 2000. This

exceeds the period of extended operation sought through this LRA. Therefore, the steam

generator FIV analysis remains valid for the period of extended operation, in accordance with

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

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I
4.7.4.2 Staff Evaluation

The ANO-2 replacement steam generators were installed in 2000. The applicant states that the

design life of the replacement steam generators extends to 2040, which exceeds the period of

extended operation sought in its LRA. The applicant concludes that the steam generator FIV

analysis remains valid for the period of extended operation, in accordance with

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

In addition to a valid FIV analysis, the ANO-2 steam generators are designed to minimize

potential FIV occurring on tubes. Steam generator tubes are supported to minimize excessive

vibration which could be detrimental to their structural integrity. The impact of FIV will most

likely cause tube wear at the intersection of antivibration bars and the tubes. However, periodic

inspections required by the applicant's Steam Generator Integrity Program will monitor and

detect any potential tube wear. On the basis of the information the applicant submitted, the

staff concludes that the applicant's TLAA of FIV on steam generator tubes meets the

acceptance criteria stated in 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii) and is therefore

acceptable.

4.7.4.3 FSARSupplement

The applicant provided the FSAR Supplement summary descriptions for the TLAA on the

Steam Generator Tubes - Flow-Induced Vibration in Section A.2.2.6.3 of Appendix A to the

LRA. The staff reviewed the FSAR Supplement summary descriptions for the TLAA, as given

in Section A.2.2.6.3 of Appendix A to the LRA. The staff determined that the FSAR description

for the TLAA provides an adequate summary of the evaluation of the TLAA for the Steam

Generator Tubes - Flow-Induced Vibration. This commitment will ensure compliance with the

requirements of 10 CFR 54.21 (c)(1)(i). Therefore,,the staff has reviewed the to the FSAR

Supplement summary description for this TLAA and concludes that it provides an adequate

summary description of the TLAA, as required by 10 CFR 54.21 (d)..

4.7.4.4 Conclusions

The staff concludes that, pursuant to 10 CFR 54.21 (c)(1)(i), the applicant has provided an

acceptable demonstration that,-for the TLAA on FIV of the steam generator tubes,the analysis

will remain valid for the period of extended operation for ANO-2, and the applicant will

adequately manage the effects of aging on the pressure boundary function for the period of

extended operation. The staff also concludes that the FSAR Supplements contain an adequate

summary description of the evaluation of TLAA for FIV, as required by 10 CFR 54.21 (d).

4.7.5 Alloy 600 Nozzle Repairs

4.7.5.1 Summary of Technical Information in the Application

In 2000, nondestructive examination evaluations revealed that a number of pressurizer heater

penetrations, as well as resistance temperature detector (RTD) and pressure measurement

nozzle penetrations on the RCS hot leg, had developed leaks. The repair for the pressurizer

heater penetration replaced the pressure boundary weld on the inside surface of the pressurizer

nozzle with an outer diameter (OD) weld attached to a temper-bead weld pad on the pressurizer

4-41
OD. The hot-leg piping penetration modification consisted of removing a portion of the old RTD

or pressure tap by cutting it near the outer wall of the RCS piping and replacing it with a new

nozzle welded on the outside surface of the RCS piping.- The applicant performed a-fracture

mechanics evaluation in order to evaluate the potential for a crack in the remaining pressurizer

and RCS hot-leg penetration welds to propagate into the pressurizer vessel or hot-leg pipe wall.

The applicant used transient cycles in the crack growth evaluations, which it assumed for a 40-

year plant lifetime. To prevent further penetration leakage, the applicant replaced all primary

piping RTD nozzles at ANO-2. The applicant qualified the replacement nozzles and attachment

welds for structural adequacy in accordance with ASME code criteria. This analysis included a

simplified fatigue evaluation which considered cyclic loads from pressure, thermal gradients,

and mechanical loads.

As discussed in Section 4.3.1 of the LRA, the applicant has completed a review of the ANO-2

fatigue transient cycle definitions. The Fatigue Monitoring Program will monitor thermal fatigue

design-basis transients, including those assumed in the analysis of the Alloy 600 nozzle repairs,

for the period of extended operation. The continued implementation of the Fatigue Monitoring

Program provides reasonable assurance that the fatigue crack growth analysis for the repairs

will remain valid during the period of extended operation. Similarly, the fatigue analysis for the

replacement nozzles and attachment welds remains valid for the period of extended operation.

This result demonstrates that the Alloy 600 nozzle repair TLAAs remain valid for the period of

extended operation, in accordance with 10 CFR 54.21 (c)(1 )(i).

4.7.5.2 Staff Evaluation

In a nozzle repair technique, the leaking (cracked) Alloy 600 nozzle is cut outboard from the

partial-penetration J-groove weld that was used to join the nozzle to the RCS hot-leg piping or

pressurizer shell. The section of the nozzle near the outer surface of the pressure boundary

component is removed and replaced with a short Alloy 690 nozzle section. The inserted Alloy

690 nozzle section is then welded to the pressure boundary component's outside surface. This

half-nozzle repair method leaves a short section of the original nozzle attached to the inside

surface with the J-groove weld and exposes the ferritic (i.e., low-alloy steel or carbon steel)

pressure boundary material to the borated water conditions of the reactor coolant.

In Section 4.7.5 of the LRA, the applicant indicated that it performed a fracture mechanics

analysis to support the ANO-2 pressurizer heater penetrations. The fracture mechanics

analysis justifies the acceptability of indications in the original J-groove weld based on a

postulated flaw size and flaw growth, considering the applicable design cycles. Based on the

results of the analysis, the applicant concluded that the postulated flaw size for the worst-case

instrument nozzle is acceptable for the remaining design life of the plant.

In RAI 4.7.5-1, the staff requested that the applicant demonstrate that the designs of repaired

nozzles will have sufficient structural integrity against the loss of material by corrosion and will

meet the minimum wall thickness requirements through the expiration of the period of extended

operation.

In response to RAI 4.7.5-1, the applicant stated that it completed analyses to estimate the

corrosion rate assuming a repaired nozzle has a through-wall crack, and the crevice between

the repaired nozzle and underlying ferritic steel will be exposed to aerated borated water. The

service lifetimes for repairs to the hot-leg pipe nozzles, pressurizer nozzles, and pressurizer

4-42
heater sleeves are 76, 56, and 196-years, respectively, before they would exceed ASME Code

limits. The most limiting service lifetime is that of 56 years for the pressurizer nozzle repair.

The 56-year lifetime from the date of the nozzle repair extends the service life beyond the

period of extended operation. Therefore, loss of material by corrosion will not impair the ability

of the repaired nozzles to maintain sufficient structural integrity for the period of extended

operation.

In RAI 4.7.5-2, the staff asked the applicant to justify and validate the CEOG conclusion that the

growth of the existing flaw in the original Alloy 82/182 J-groove weld material by stresscorrosion cracking into the carbon steel or low-alloy steel base metal is not a plausible effect*

during the period of extended operation.

In response to RAI 4.7.5-2, the applicant stated that the repaired nozzles will have cracks in the

Alloy 600 nozzles or the partial penetration attachment welds remaining after completing the

repair. Since residual stresses from the welding will remain, these cracks may continue to

propagate through'the nozzle/weld metal by-stress-corrosion cracking to the carbon or low-alloy

steel base metal. Further growth into the carbon or low-alloy steel base metal is unlikely since

low oxygen levels resulting from PWR Water chemistry will result in corrosion potentials below

the critical cracking potential in a high-ternperature environment. As described in Section ' -

B.1.30.3 of the LRA, the applicant based the ANO-2 Primary Water Chemistry Control Program

on the Electric Power Research Institute TR-1 05714, which requires stringent oxygen controls.

This program will continue into the period of extended operation. Therefore, the applicant

concluded that the ANO-2 Primary WaterChemistry.Program will provide an environment which

limits the corrosion potential of the applicable material below the critical cracking potentials, and

stress-corrosion cracking will not cause growth of the existing flaw into the carbon steel or lowalloy steel base metal. The staff finds the response'acceptable and considers this issue closed.

It should be noted that Westinghouse Electric Corp. has revised CE NPSD-1 198-P, Revision

00, since the staff issued its review of the report (as given in the staff's SE of February 8,

2002), and since the applicant issued its response (October 10, 2002). The revisions to the

topical report address potential issues with the original boric acid wastage analysis for the halfnozzle designs' that came up as a result of the boric acid corrosion (wastage) event of the

Davis-Besse RV head, and they also address a design'calculation error Westinghouse

discovered in the original fatigue crack growth analysis for the half-nozzle designs. The Class 2

proprietary report, WCAP-15973-P, "Low-Alloy Steel Component Corrosion Analysis Supporting

Small-Diameter Alloy 600/690 Nozzle Repair/Replacement Programs," issued November 2002,

provides the revisions, which the applicant submitted to the NRC for review and approval in

letter CEOG-02-243, dated November 11, 2002.; This report applies to the ANO-2 half-nozzle

designs.

4.7.5.3 FSAR Supplement

The applicant provided the FSAR Supplement summary descriptions for the TLAAs on the Alloy

600 nozzle repairs in Section A.2.2.6.4 of Appendix A to the LRA. The staff reviewed the FSAR

Supplement summary descriptions for the TLAA, as given in Section A.2.2.6.4 of Appendix A to'

the LRA: The staff determined that the FSAR descriptions for the TLAA on the nozzle repairs

provide an adequate summary of the evaluation of the TLAA for the ANO-2 nozzle repairs.

This commitment will ensure compliance with the requirements of 10 CFR 54.21 (c)(1) 'and 10

4-43
CFR 50.55a(a)(3). The staff therefore concludes that the FSAR Supplement summary

descriptions for the TLAA are acceptable.

4.7.5.4 Conclusions

The staff concludes that the applicant has provided an adequate demonstration pursuant to 10

CFR 54.21 (c)(1 )(ii) that, for the nozzle repairs TLAA, the applicant has projected the analyses

to the end of the period of extended operation. The staff also concludes that the FSAR

Supplements contain an adequate summary description of the evaluation of this TLAA for the

period of extended operation, as required by 10 CFR 54.21(d).,

4.7.6 High-Energy Line Break Analyses

4.7.6.1 Summary of Technical Information in the Application

The applicant stated in Section 4.7.6 of the LRA that, in accordance with GDC 4, it has taken

special measures in the design and construction of ANO-2 to protect SSCs required to place

the reactor in a safe, cold-shutdown condition from the dynamic effects associated with the

postulated rupture of piping. The applicant used RG 1.46, "Protection Against Pipe Whip Inside

Containment," in establishing the design criteria for piping systems inside the containment. As

defined in SAR Section 3.6.2.1, the applicant determined the postulated break locations for

ASME Code, Section III, Class 1 piping, in part, using any intermediate locations between

terminal ends where the CUF derived from the piping fatigue analysis under the loadings

associated with specified seismic events and operational plant conditions exceeded 0.1

(Reference 4.7-3). As discussed in Section 4.3 of this SER, these fatigue evaluations are

TLAAs since they are based on a set of design transients that are dependent on the life of the

plant.

Fatigue evaluations for Class 1 mechanical components at ANO-2, as described in Section

4.3.1 of the LRA, demonstrate ample margin exists between the projected and analyzed

number of thermal cycles for all Class 1 components for the period of extended operation.

Therefore, the analyzed usage factors the applicant employed for the current HELB location

determinations remain valid for the period of extended operation.

In addition, the applicant stated that ANO-2 monitors transient cycles that contribute to fatigue

usage in accordance with requirements in the ANO-2 TSs, Section 6.8.4(b). The continued

implementation of the ANO-2 Fatigue Monitoring Program, which the applicant discussed in

Appendix B to the LRA, also provides reasonable assurance that the ANO-2 HELB analyses will

remain valid during the period of extended operation. The applicant concluded that this result

demonstrates that the HELB TLAA remains valid for the period of extended operation, in

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

4.7.6.2 Staff Evaluation

In RAI 4.7.6-1, the staff asked the applicant to indicate that it reevaluated the surge line fatigue

TLAA to determine if additional intermediate pipe breaks needed to be postulated at locations

where the CUF may exceed the pipe break postulation criterion for Class 1 piping (CUF=0.1),

stated in SAR Section 3.6.2.1, during the period of extended operation. In its response, the

4-44
applicant stated that the number of RCS transients assumed in the original design is greater

than the number projected for 60 years of operation, and therefore the CUFs will not exceed the

criterion for intermediate breaks and remain valid for the period of extended operation. Since

the CUFs do not change, no new break locations need to be postulated. The staff concurs with

the applicant's conclusion that it need not postulate any new breaks.

The staff has reviewed the technical information in Section 4.7.6 of the LRA regarding the

fatigue TLAAs for the postulation of HELB in ASME Code, Section 1II, Class 1 piping, including

the response to RAI 4.7.6.1. The staff finds the information adequate because the applicant

has demonstrated that the fatigue TLAAs which form the basis for postulating HELBs,- in

accordance with SAR Section 3.6.2.1, will remain valid during the period of extended operation,

in accordance with 10 CFR 54.21(c)(1)(i). ;-,--- .-

4.7.6.3 FSAR Supplement

The applicant provided the FSAR Supplement summary descriptions for the TLAAs on the

High-Energy Line Break Analyses in Section A.2.2.6.5 of Appendix A to the LRA. The staff

reviewed the FSAR Supplement summary descriptions for the TLAA, as given in Section

A.2.2.6.5 of Appendix A to the LRA. The staff determined that the FSAR description for the

TLAA provides an adequate summary of the evaluation of the TLAA for the High-Energy Line

Break Analyses. This commitment will ensure compliance with the requirements of 10 CFR

54.21 (c)(1 )(i). Therefore, the staff has reviewed the to the FSAR Supplement summary

description for this TLAA and concludes that it provides an adequate summary description of

the TLAA, as required by 10 CFR 54.21 (d).

4.7.6.4 Conclusions

Section A.2.2.6.5 of the LRA provides the applicant's supplement for the ANO-2 FSAR

regarding the HELB fatigue TLAA of ASME Code, Section 1I1, Class 1 piping. The staff has

reviewed the supplemental section and finds it acceptable because it provides a reasonable

summary of the information the applicant presented in Section 4.7.3 of the LRA.

On the basis of its review, the staff concludes that the applicant has provided an adequate

demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i), that the TLAAs that form the basis for

postulating HELB remain valid for the period of extended operation.

The staff also concludes that the FSAR Supplement contains an appropriate summary

description of the HELB TLAA evaluation for the period of extended operation, as required by

10 CFR 54.21 (d).

4-45
4.8 Conclusions for Time-Limited Aqinu Analvses

The staff has reviewed the information in Section 4, "Time-Limited Aging Analysis", of the LRA.

On the basis of its review, the staff concludes that the applicant has provided an adequate list

of TLAAs, as defined in 10 CFR 54.3. Further, the staff concludes 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 aging effects will be

adequately managed for the period of extended operation, as required by

10 CFR 54.21 (c)(1 )(iii). The staff has also reviewed the FSAR Supplements for the TLAAs and

finds that the FSAR Supplement contains descriptions of the TLAA's sufficient to satisfy the

requirements of 10 CFR 54.21 (d). In addition, the staff concludes that no plant-specific

exemptions are in effect that are based on TLAA's, as required by 10 CFR 54.21 (c)(2).

With regard to these matters, the NRC staff has concluded that there is reasonable assurance

that the activities authorized by the renewed licenses will continue to be conducted in

accordance with the current licensing basis, and that any changes made to the ANO-2 current

licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the

Commission's regulations.

4-46
5. REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) related to the renewal of operating

license for Arkansas Nuclear One, Unit 2 on November 5, 2004. On December 1, 2004, 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 April 7, 2005.

During the 522nd meeting of the ACRS, May 5-6, 2005, the ACRS completed its review of the

Arkansas Nuclear One, Unit 2 license renewal application and the NRC staff's SER. The ACRS

documented its findings in a letter to the Commission dated May 13, 2005. A copy of this letter

is provided on the following pages of this SER.

.' ." -- :' !

.: - f, .'.J

I I I.: -lI

:~ :. ~ - \; : ; I

5-1
ACRSR-2124

May 13, 2005

The Honorable Nils J. Diaz

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 2005-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR ARKANSAS NUCLEAR ONE, UNIT 2

Dear Chairman Diaz:

During the 522nd meeting of the Advisory Committee on Reactor Safeguards, May 5-6, 2005,

we completed our review of the license renewal application for Arkansas Nuclear One, Unit 2

(ANO-2), and the associated final Safety Evaluation Report (SER) prepared by the NRC staff.

Our Plant License Renewal Subcommittee also reviewed this matter during a meeting on

December 1, 2004. During our review, we had the benefit of discussions with representatives

of the NRC staff and Entergy Operations, Inc. (Entergy). We also had the benefit of the

documents referenced. This report fulfills the requirements of 10 CFR 54.25 that the ACRS

review and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage age-related

degradation provide reasonable assurance that ANO-2 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 Entergy application for renewal of the operating license for ANO-2 should be

approved.

BACKGROUND AND DISCUSSION

ANO-2 is a Combustion Engineering pressurized water reactor rated at 3026 MWt, enclosed in

a large dry containment building. The current power rating includes a 7.5% power uprate

implemented in 2002. The ANO-2 steam generators were replaced with new Westinghouse

Delta steam generators with Alloy 690 tubing in conjunction with this power uprate.

Entergy requested renewal of the ANO-2 operating license for 20 years beyond the current

license term, which expires on July 17, 2018. In the final SER, the staff documents its review of

5-2

I
the license renewal application and other information submitted by Entergy and obtained during

the audits and inspections 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 plausible aging mechanisms associated with passive, long-lived components; the adequacy

of the applicant's aging management programs; and the identification and assessment of timelimited aging analyses (TLAAs). -

The ANO-2 application demonstrates consistency with the Generic Aging Lessons Learned

(GALL) Report or documents deviations from the approaches specified in that report. The

ANO-2 application is the second one evaluated by the staff using the new audit and review

process developed to confirm consistency with, and the acceptability of deviations from, the -

GALL Report. The new process requires that more review activities be conducted at the site.

As in the first application, this approach has resulted in more effective interactions between the

applicant and the staff and has significantly reduced requests for additional information (RAls).

During its review, the staff identified several components that the applicant should have

included in the scope of license renewal but did not. The applicant subsequently brought them

into scope. The staff concluded that these omissions were the result of minor oversights or

different interpretations of the scoping methodology, and not an indication of process problems.

The staff also concluded that the applicant's scoping and screening processes have

successfully identified SSCs within the scope of license renewal and subject to an aging

management review. We agree with these conclusions.

The applicant performed a comprehensive aging management review of all SSCs within the

scope of license renewal. In the application, Entergy describes 34 aging management

programs for license renewal, including existing, enhanced, and new programs. We agree with

the staff's conclusion that these programs are adequate.

Implementation is key to effective aging management programs. Although the applicant's

Structures Monitoring-Masonry Wall Program is consistent with the GALL Report, the staff's

audit of this program revealed that the initial baseline examinations were not documented

properly, the first 5-year reexamination was not performed, and qualifications for personnel responsible for walkdowns were not established. The Annual Assessment Letter for ANO,

Units 1 and 2, dated March 3, 2004, had already identified a substantive cross-cutting issue

concerning problem identification and resolution. Based on the Annual Assessment Letter

dated March 2, 2005, the weaknesses in the ANO-2 Problem Identification and Resolution

Program appear to have been corrected. Maintaining an effective problem identification and

resolution program is critical to the success of the aging management programs.

As in previous reviews, we questioned the adequacy of relying on opportunistic inspections of

inaccessible buried piping and tanks, in lieu of periodic inspections at a plant-specific

frequency, as specified in the GALL Report. The applicant has committed to enhance its

Buried Piping Inspection Program by performing an inspection within 10 years of entering the

period of extended operation unless an opportunistic inspection has occurred within this 1 0-year

period. This program enhancement is appropriate..

The applicant identified and reevaluated systems and components requiring TLAAs for 20 more

years of operation. The applicant's analyses of reactor vessel embrittlement (upper shelf

5-3
energy, pressurized thermal shock, and pressure-temperature limits), independently verified by

the staff, demonstrate that the limiting beltline materials will satisfy the acceptance criteria at 48

effective full-power years (EFPYs). This value corresponds to a constant capacity factor of

80% for 60 years. We questioned the use of 48 EFPYs, rather than the 54 EFPYs used by

other applicants to bound 60 years of operation. Given the current performance of the fleet, 54

EFPYs seems to be a more appropriate value for 60 years of operation. The staff

independently verified that the upper shelf energy and pressurized thermal shock acceptance

criteria would still be met at 54 EFPYs.

In 2000, nondestructive examinations revealed a number of leaks in pressurizer and hot-leg

penetration nozzles. The applicant implemented repairs using the half-nozzle repair technique.

The applicant evaluated the potential for existing flaws in the remaining pressurizer and hot-leg

penetration welds to propagate into the pressurizer or hot leg. The applicant has performed a

TLAA to bound the period of extended operation and has demonstrated that stress corrosion

cracking will not cause existing flaws to propagate into the carbon steel or low-alloy steel base

metal.

Since a shroud prevents a complete 3600 bare metal visual inspection of some of the control

rod drive mechanism (CRDM) penetrations, the applicant performed alternative eddy current

and volumetric inspections. Although these inspections did not identify any cracking or

leakage, ANO-2 is ranked as highly susceptible to CRDM cracking. The applicant has

scheduled the procurement of a new reactor vessel head in 2006. Meanwhile, the applicant

plans to modify the shroud to allow increased access for visual examinations.

We agree with the staff that no issues related to the matters described in 10 CFR 54.29(a)(1)

and (a)(2) preclude renewal of the operating license for ANO-2. The programs established and

committed to by Entergy provide reasonable assurance that ANO-2 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 Entergy application for renewal of the operating

license for ANO-2 should be approved.

Sincerely,

/RAI

Graham B. Wallis

Chairman

References

1. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Arkansas Nuclear One, Unit 2," April 2005

2. Entergy Operations Inc., "License Renewal Application Arkansas Nuclear One - Unit 2,"

October 2003

3. U.S. Nuclear Regulatory Commission, "Draft Safety Evaluation Report Related to the

License Renewal of the Arkansas Nuclear One, Unit 2," November 2004

4. U.S. Nuclear Regulatory Commission, "Arkansas Nuclear One, Unit 2 - NRC License

Renewal Scoping and Screening Inspection Report 05000368/2004-06," April 19, 2004

5-4

I
5. Information Systems Laboratories, Inc., "Audit and Review Report for Plant Aging

Management Reviews and Programs, Arkansas Nuclear One - Unit 2," July 29, 2004

5-5
6. CONCLUSIONS

The staff of the U.S. Nuclear Regulatory Commission (NRC or Commission) reviewed the

license renewal application for Arkansas Nuclear One, Unit 2, in accordance with Commission

regulations and NUREG-1 800, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," dated July, 2001. Title 10, Section 54.29, of the Code

of Federal Regulations (10 CFR 54.29) provides the standards for issuance of a renewed

license.

On the basis of its evaluation of the license renewal application, the NRC staff has determined

that the requirements of 10 CFR 54.29(a) have been met.

The NRC staff notes that any requirements of Subpart A of 10 CFR Part 51 are documented in

Supplement 19 to NUREG-1437, "Generic Environmental Impact Statement for License

Renewal of Nuclear Plants: Regarding Arkansas Nuclear One - Unit 2. Final Report", dated

April 2005.

6-1
APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL

During the review of the Arkansas Nuclear One, Unit 2, LRA by the NRC staff, the applicant made commitments related to aging

management programs (AMPs) to manage aging effects of structures and components (SCs) prior to the period of extended

operation. The following table lists these commitments, along with the implementation schedule and the source of the commitment.

ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

___:_I'__' Alloy 600 Program

1 ANO-2 will'submit a description of the Alloy 600 Aging At least 24 months Letter 2CAN090402,

Management Programi, which includes the inspection plan, to prior to th period of Attachment 2,' pg 6.

the NRC-staff for review and approval. ; ; , exterinde'd operation ''_''

- -- 2 - The FSAR Supplement-A.2.1.1-will be revised to state the "--- Uponissuance-of the- Letter 2CAN090403,

following: ' ' - - renewed license. Attachment 1, pg 2

The Alloy 600 Aging Management Program will manage aging Letter 2CAN090403,

effects of alloy 600/690 items and alloy 52/152 and 82/182 Attachment 1

welds in the reactor coolant system that are not addressed by

the Reactor Vessel Head Penetration Inspection Program,

Section A.2.1.21, and the Steam Generator Integrity Program,

Section A.2.1 .26. This program will detect primary water stress

corrosion cracking (PWSCC) by using the examination and

inspection requirements of ASME Section Xl, as augmented by

the commitments made by the applicant in NRC

correspondence.- - -

A-1
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

3 A description of the Alloy 600 Aging Management Program, At least 24 months Letter 2CAN090403,

which includes the inspection plan, will be submitted to the prior to the period of Attachment 2, pg 1.

NRC for review and approval. The submittal date will be at extended operation

least 24 months prior to the period of extended operation.

Buried Piping Inspection Program

4 The Buried Piping Inspection Program will include preventive Prior to entering the ANO-2 LRA, Appendix

measures to mitigate corrosion and periodic inspection to period of extended A, Section A.2.1.4

manage the effects of corrosion on buried carbon steel piping. operation.

Preventive measures will be in accordance with standard

industry practice for maintaining external coatings and

wrappings. Buried pipes will be inspected when they are

excavated during maintenance.

Cast Austenitic Stainless Steel (CASS) Evaluation Program

5 The CASS evaluation program will augment the inspection of Prior to entering the ANO-2 LRA, Appendix

reactor coolant system components in accordance with the period of extended A, Section A.2.1.5.

ASME Boiler and Pressure Vessel Code, Section Xl. The operation.

CASS evaluation program will manage the effects of loss of

fracture toughness in reactor coolant system CASS

components susceptible to thermal aging embrittlement using

additional inspections and a component-specific flaw tolerance

evaluation.

A-2
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Environmental Qualification of Electrical Components

6 Entefoy will continue to include the entire length of cable from Prior to entering the Letter 2CAN01 0401,

the detector to the control room instrumentation in the EQ period of extended Attachment 1, pg 1.

program during the period of extended operation even though operation.

this is not required by 10 CFR 50.49.

Fire Water System Program

7 The Fire Water System Program will be enhanced to inspect a Prior to entering the ANO-2 LRA, Appendixsample of sprinkler heads using the guidance in NFPA 25. period of extended A, Section A.2.1.11.

-_ - ,operation..

* 

I' . - t : -1

A-3
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Heat Exchanger Monitoring Program

8 The Heat Exchanger Monitoring Program will manage loss of Prior to entering the ANO-2 LRA, Appendix

material and cracking, as applicable, on heat exchangers in period of extended A, Section A.2.1.13.

various systems. The Heat Exchanger Monitoring Program will operation.

inspect heat exchangers for degradation using non-destructive

examinations, such as eddy-current inspections and visual Letter 2CANO10401

inspections. If degradation is found, then an evaluation will be Attachment 1, pg 2

performed to determine its effects on the heat exchanger's

design functions.

Letter 2CAN01 0401

The acceptance criterion for the tube eddy current inspections Attachment 1, pg 2

of the heat exchanger monitoring program will be wall-loss less

than 60% through-wall.

Ferritic stainless steel tubes in the shutdown cooling heat

exchanger of the Heat Exchanger Monitoring Program will be

monitored, where practical, using appropriate non-destructive

examination (NDE) techniques such as eddy current testing

with specific NDE processes suitable for ferritic stainless

material.

9 Entergy will perform a fatigue evaluation showing the Prior to the end of the Letter 2CAN030401

acceptability of the regenerative heat exchangers for the period current operating Attachment 1, pg 2

of extended operation or the regenerative heat exchangers will license term.

be replaced.

Non-EQ Insulated Cables and Connections Program

10 The Non-EQ Insulated Cables and Connections Program will During the period of ANO-2 LRA, Appendix

apply to accessible (i.e., able to be approached and viewed extended operation. A, Section A.2.1.17.

easily) insulated cables and connections installed in structures

within the scope of license renewal and prone to adverse

A-4
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Periodic Surveillance and

Preventive Maintenance

11 The Periodic Surveillance and Preventive Maintenance (PSPM) Prior to entering the Letter 2CAN080401

Program will manage the effects of aging on flexible hoses period of extended Attachment 2, pg 3

through visual examination of external and internal surfaces. operation.

This visual examination looks for evidence of cracking and

changes in material properties such as loss of flexibility and Letter 2CAN060402

embrittlement. The flexibility of the hoses will be verified Attachment 2, pg 1

through physical manipulation of the hose concurrent with the

visual inspection.,

The details on inspection criteria and frequency for the flex

hoses that are included in the PSPM Program will be

determined prior to entering the period of extended operation.

It is expected that a visual inspection of.the internal and

external surfaces will be performed. However, it may be

determined that periodic replacement of the hoses is preferable

and inspections will not be performed.

If evidence of degradation is detected, the hoses will be

replaced. .These hoses will be inspected at least once every 10

years. The hoses that credit the PSPM Program are in the

emergency diesel generator, fuel oil, alternate AC, and nitrogen

systems. Alternatively, periodic replacement of the hose may

be implemented in lieu of 'periodic inspection.

A-5
ITEM 

l

I NI IMRFR 

I

COMMITMENT IMPLEMENTATION

IMrwEMnl 11ATI

SOURCE
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Reactor Vessel Internals Cast Austenitic Stainless Steel

(CASS) Program

15 The Reactor Vessel Internals CASS Program will manage aging At least 24 months ANO-2 LRA, Appendix

effects of cast austenitic stainless steel reactor vessel internals prior to the period of A, Section A.2.1.23.

components. This program will supplement the reactor vessel extended operation

internals inspections required by the ASME Section Xi Inservice

Inspection Program. The program will manage cracking, Letter 2CAN090402

reduction of fracture toughness, and dimensional changes Attachment 2, pg 7

using inspections of applicable components which will be

determined based on the neutron fluence and thermal Letter 2CAN1 00403,

embrittlement susceptibility of the component. Attachment 2, pg 1

A description of the the Reactor Vessel Internals CASS

Program, which includes the inspection plan, will be submitted

to the NRC for review and approval.

16 ANO-2 will begin inspections under the Reactor Vessel (RV) During the period of Letter 2CAN050401

Internals CASS Program during the 20-year period of extended extended operation. Attachment 2, pg 1

operation, and the inspections will be performed once during

the period. ANO-2 plans to perform the inspections of the RV

internals CASS components in the fifth inspection interval. The

need for subsequent inspections will be based on the results

from this inspection.

17 Engineering Report A2-EP-2002-002-0, Section 3.8.2.B.5, Prior to entering the Letter 2CAN050401

Detection of Aging Effects will be revised to reference period of extended Attachment 2, pg 2

enhanced VT-1 only as follows, "The enhanced VT 1 operation.

examinations of CASS reactor vessel internal parts will be

performed one time during the period of extended operation.

A-7
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

18 Table 5.2-12, note (a) of the FSAR will be revised to add the Upon Issuance of the Letter 2CAN01 0401

following statement: renewed licences. Attachment 1, pg 1

The ANO-2 specimen capsule withdrawal schedule will be

revised to withdraw and test a standby capsule to cover the

peak fluence expected through the end of the period of

extended operation.

A-8

I]
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER ''. SCHEDULE

Reactor Vessel Internals Stainless Steel Plates, Forgings,

Welds, and BoltingProgram 'rn

19 The Reactor Vessel Internals Stainless Steel Plates, Forgings, At least 24 months ANO-2 LRA, Appendix

Welds, and Bolting Program will manage aging effects of prior to the period of A, Section A.2.1.24.

reactor vessel internals plates, forgings, welds, and bolting. extended operation.

This program will supplement the reactor vessel internals

inspections required by the ASME Section Xl inservice Letter 2CAN050401

inspection program. This program will manage the effects of Attachment 2, pg 2

crack initiation and growth due to stress corrosion cracking or

irradiation assisted stress corrosion cracking, loss of fracture

toughness due to neutron irradiation embrittlement, and Letter 2CAN090402

distortion due to void swelling. This program will provide visual. Attachment 2, pg 7

inspections and non-destructive examinations of reactor vessel

internals. . A- . ' ' . Letter 2CAN1 00403,

; : -- Attachment 2, pg 1

In the development of this program, Entergy will support reactor

vessel internals aging effects research through EPRI, the

Materials Reliability Program, and other applicable industry

efforts to better characterize the internals aging effects and to

provide material property data to generate acceptance

standards for inspections. Appropriate examination techniques

will be selected based on the results of these industry efforts.

A description of this program, which includes the inspection

plan, will be submitted to the NRC for review and approval.

A-9
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

20 Engineering Report A2-EP-2003-002-0, Section 3.8.1.B 6.b will Prior to entering the Letter 2CAN090402

be revised to include the following statement: "Any indication period of extended Attachment 2, pg 2

or relevant condition of degradation will be evaluated -in operation.

accordance with ASME Code Section Xl, IWB-3100 by

comparing inservice inspection results with acceptance

standards of IWB-3400 and IWB-3500."

Steam Generator Integrity Program

21 The ANO-2 Steam Generator Integrity Program manages the During the period of Letter 2CAN070404

applicable aging effects for the anti-vibration bars and tube extended operation. Attachment 2, pg 1

support plates. The program requires visual inspection of the

steam generator lower internals (tube support structures and

tube bundle). This inspection is completed at least once every

five years. This inspection checks for loose parts as well as

corrosion and other damage in this region. An integrity

assessment is performed after each steam generator

inspection which addresses all known degradation mechanisms

in the steam generator being evaluated.

The ANO-2 Steam Generator Integrity Program will include

visual inspection of the steam generator lower internals (tube

support structures and tube bundle including the U-bend). This

inspection is completed at least once every five years.- This

inspection checks for loose parts as well as corrosion and other

damage in this region.

The steam generator upper internals (moisture separators)

require a thorough visual inspection once every five years. This

inspection examines for mechanical damage, corrosion, or

other unusual conditions.

A-10
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULEService Water Integrity Progralm

22 The Service Water Integrity Program will be enhanced to check Prior to entering the Letter 2CAN070409

- for evidence of selective leaching during visual inspections. period of extended Attachment 2, pg 1

Specific details on the enhancements to the' Service Water operation.

Integrity Program for, managing loss of material ddue to selective

leaching will be developed prior to the period of extended

operation. The enhancements to the program to manage loss

of material due to selective leaching will be consistent with

NUREG-1801 Aging Management Program XL.M33 which

includes hardness testing. '

.-z--Structures Monitoring__-;Masonry Wall Program '__________

- 23 - - -The Structures Monitoring - Masonry Wall Program will manage During the period'of ANO-2 LRA, Appendix

cracking of hasonry walls within the scope of license renewal. extended operation. A, Section A.2.1.27.

Masonry walls'are visually'insp6cted as'pat of the Structures

Monitoring -Masonry Wall Program conducted pursuant'to the

Maintenance Rule, 1 OCFR50.65.

A-11
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Structures Monitoring - Structural Monitoring

24 Wells are no longer available for sampling groundwater. During the period of Letter 2CAN080401

Consequently, in lieu of sampling groundwater to confirm that it extended operation. Attachment 2, pg 1

remains non-aggressive, concrete exposed to groundwater is

included in the Structures Monitoring - Structural Monitoring

Program for inspection to confirm the absence of aging effects.

Under the Structures Monitoring - Structural Monitoring

Program concrete exposed to lake water is periodically

inspected. Since take water chemistry is representative of

groundwater chemistry, results of these inspections will be

representative of underground concrete exposed to

groundwater. In addition, when excavated for maintenance

activities, inaccessible concrete exposed to groundwater will be

visually inspected under the Structures Monitoring - Structural

Monitoring Program.

System Walkdown Program

25 The System Walkdown Program will include inspections to Prior to entering the ANO-2 LRA, Appendix

manage loss of material, loss of mechanical closure integrity period of extended A, Section A.2.1.29.

and cracking, as applicable, for systems and components within operation.

the scope of license renewal. The program will use general

visual inspections of readily accessible system and component

surfaces during system walkdowns.

Wall Thinning Monitoring Program

26 In lieu of disassembling the expansion joints in the AAC diesel, During the period of Letter 2CAN060402

nondestructive examinations such as ultrasonic testing of the extended operation. Attachment 2, pg 1

expansion joints will be performed as part of the Wall Thinning

Monitoring Program to detect loss of material and cracking.

A-12
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

27 Wall thickness will be the parameter monitored for the Wall During the period of ANO-2 LRA, Appendix Thinning Monitoring Program. The method of detection of extended operation. A, Section A.2.1.30.

aging effects will be non-destructive examinations using

industry-accepted methods, such as ultrasonic testing, to Letter 2CAN01 0401

determine wall thickness of susceptible components. Attachment 1, pg 2

Inspections will be performed to ensure wall thickness is above

the minimum required in order to avoid failures.

Water Chemistry Control - Primary and Secondary Water - Chemistry Control Program

28 The FSAR Supplement for the Primary and Secondary Water Upon issuance of the Letter 2CAN050401

Chemistry Program, LRA Section A.2.1.33, will be revised to renewed license Attachment 2, pg 2

include a reference to the EPRI reportsTR-105714 and

TR-102134 used in the development of the program.s;:. -_ _ _ _ _

I : .

A-13
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

One-Time Inspection Program

29 ANO-2 will implement a One-Time Inspection Program for the Prior to entering the Letter 2CAN090402

components subject to aging management review that were period of extended Attachment 2, pg 2

included for 1OCFR54.4(a)(2) in the following systems. operation.

* Auxiliary building heating and ventilation

* Auxiliary building sump

* Drain collection header

* Liquid radwaste management

* Post accident sampling

* Resin transfer

* Regenerative waste

* Spent resin

The ANO-2 One-Time Inspection Program will be consistent

with the program description in NUREG-1801 Vol. 2, XL.M32,

One-Time Inspection. Adverse conditions identified during the

inspections will be addressed as part of the ANO-2 Corrective

Action Program. Corrective actions may include additional

inspections, if warranted based on the inspection results.

A-14

El
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

30 The following description of the One-Time Inspection Program Upon Issuance of Letter 2CAN090402

will be added to the FSAR Supplement as Section A.2.1.34: renewed license Attachment 2, pg 3

A.2.1.34 ONE-TIME INSPECTION

The One-Time Inspection Program confirms that the aging

effects are being adequately managed for components in raw

or untreated water. This program will perform destructive'or

nondestructive Inspections on internal surfaces of a sample of

components in the following systems.

* ' Auxiliary building heating and ventilation

* Auxiliary building sump,

* - Drain' collection header

* - Liquid radwaste management

* Post accident sampling

*-: i iResin trahsfer^ '

* Regenerative waste

* Spent resin'

The One-Time Inspection Program will be initiated prior to the

period of extended operation.

A-15
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Concrete Containment

Tendon Prestress

31 Loss of tendon prestress will be managed during the period of Prior to entering the Letter 2CAN090402

extended operation by continued implementation of tendon period of extended Attachment 2, pg 4

inspections required by ASME Code Section Xl IWL. Relevant operation.

operating experience, including experience with prestressing

systems described in NRC Information Notice (IN) 99-10, will

be considered during inspections and data analysis.

Prior to the entering the period of extended operation, trend

lines for ANO-2 tendon prestressing forces will be developed

using regression analysis in accordance with guidance provided

in NRC Information Notice (IN) 99-10. If future tendon

examination data diverge from the expected trend, the

discrepancy will be addressed in accordance with requirements

of the Containment Inservice Inspection (ISI) Program

(IWE/IWL) and the current licensing basis. Specifically, if

prestressing force trend lines indicate that existing prestressing

forces in the containment would go below the minimum

required values (MRVs) prior to the next scheduled inspection

(Reference 10CFR50.55a(b)(2)(ix)(B) or

10CFR50.55a(b)(2)(viii)(B)), then systematic retensioning of

tendons, a reanalysis of the containment or a reanalysis of the

post-tensioning system is required to ensure the design

adequacy of containment.

A-16
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

32 The FSAR Supplement for Section A.2.2.4 will be revised as Upon issuance to the' Letter 2CAN090402

follows: renewed license. Attachment 2, pg 5

A.2.2.4 CONCRETE CONTAINMENT TENDON PRESTRESS

The analysis of lo'ss of prestress in the containment building

post-tensioning system is a time-limited aging analysis. Loss of

tendon prestress in the containment building post-tensioning

system will be managed for license renewal in accordance with

the Containment ISI Program. This program, discussed in

Section A.2.1.14, includes tendon surveillance testing. Prior to

the period of extended operation, trend lines for ANO-2 tendon

prestressing forces will be developed using regression analysis

in accordance with guidance provided in NRC IN 99 10. If

prestressing force trend lines indicate that existing prestressing ..-

forces in the containment would go below the minimum

required values (MRVs) prior to the next scheduled inspection- . - (Reference 10CFR50.55a(b)(2)(ix)(B) or 10CFR

50.55a(b)(2)(viii)(B)), then systematic retensioning of tendons,

a reanalysis of the containment or a reanalysis of the post

tensioning system is required to ensure the design adequacy of

containment.

A-17
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Reactor Coolant Pump Flywheel

33 The FSAR Supplement for Section A.2.2.6.6 will be revised as Upon issuance of the Letter 2CAN090402

follows: renewed license. Attachment 2, pg 6

The flaw growth analysis associated with the reactor coolant

pump motor flywheel is conservatively treated as a time-limited

aging analysis. The analysis addresses the growth of

pre-existing cracks subjected to 4,000 reactor coolant pump

motor startup or shutdown cycles, which exceeds by a factor of

eight the number of RCP cycles projected through the period of

extended operation. Therefore, the flaw growth analysis

remains valid for the period of extended operation.

Miscellaneous Systems

34 The FSAR Supplement will be revised as follows: Upon issuance of the Letter 2CAN050403

renewed license. Attachment 2, pg 1

The Quality Assurance Program implements the requirements

of 1 OCFR50, Appendix B. The Quality Assurance Program

-includes the elements of corrective action, confirmation

process, and administrative controls and is applicable to all

aging management programs credited for license renewal

including programs for safety-related and non-safety related

structures, systems and components.

35 The intake canal is periodically inspected as part of the ANO During the period of Letter 2CAN080401

Maintenance Rule Program. Periodic inspections will continue extended operation. Attachment 2, pg 1

during the period of extended operation.

A-18
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

36 Periodic maintenance will be used to manage the loss of During the period of Letter 2CAN060402

material in the Starting Air System for the AAC diesel. The use extended operation. Attachment 2, pg 1

of periodic maintenance will ensure the proper operation of the

air dryers such that significant moisture will not be entrained in

the portion of the system that is subject to aging management

review.

37 Periodic inspections will be used to manage the loss of material During the period of Letter 2CAN060402

in the Starting Air System for the EDGs. extended operation. Attachment 2, pg 1

38 For gray cast iron, ANO-2 will manage loss of material due to During the period of Letter 2CAN030401

selective leaching by one of the following programs that include extended operation. Attachment 1, pg 1

the management of loss of material due to selective leaching.

_. _Periodic Surveillance and Preventive Maintenance

ServiceWater Integrity Program - . --.

Fire Protec'tlocn Program

. Environmentally-Assisted Fatigue (GSI-1 90)

39 Should ANO-2 select the inspection option (Option 4) to Prior to entering the License Renewal

manage environmentally-assisted fatigue, details of the scope, period of extended Application, pg. 4.3-6 -

qualification, method, and frequency of the inspections will be operation.

provided to the NRC for review and approval prior to entering

the period of extended operation.

. ..1 . '

A-19
ITEM COMMITMENT IMPLEMENTATION SOURCE

NUMBER SCHEDULE

Non-EQ Inaccessible Medium-Voltage Cables

40 The ANO-2 "Non-EQ Inaccessible Medium-Voltage Cable Prior to entering the Letter 2CAN020502

Program" will include testing of underground medium-voltage period of extended Attachment 1, pg 1

cables exposed to significant voltage that perform a license operation.

renewal intended function, regardless of preventive actions to

prevent exposure to significant moisture.

Additional Commitments

41 The chemistry procedure and engineering report will be revised Prior to entering the Letter 2CAN120403

to address loss of the passive layer if chemistry limits are out of period of extended Attachment 1, pg 1

specification for an extended period. operation

42 The PSPM Program will be revised to include an inspection of Prior to entering the Letter 2CAN1 20403

the alternate AC diesel generator starting air tank. period of extended Attachment 1, pg 1

_ _operation

A-20
APPENDIX B: .CHRONOLOGY

This appendix contains a chronological listing of the' routine licensing correspondence between

the U.S. Nuclear Regulatory Commission (NRC)'staff and the Entergy Operations, Inc.

(Entergy), and other correspondence regarding the NRC staff's reviews of the Arkansas

Nuclear One, Unit 2 (ANO-2), (under Docket Number 50-368) license renewal application

(LRA).

October 14, 2003

October 21, 2003

In a letter (signed bylC. Anderson), Entergy submitted its LRA for the

Arkansas Nuclear One, Unit 2.; ML032890492

In a letter (signed by:P.-Kuo), NRC informed Entergy of the receipt of the'

LRA for ANO-2 and Gregory Suber will be the PM for safety review and

Thomas Kenyon will be PM for environmental review. ML032940160

November 14,2003 In a letter (signed by P)Kuo), NRC informed Entergy the LRA was

accepted and sufficient for docketing and proposed review schedule and

- issued notice of opportunity for hearing for the LRA of ANO-2.'

ML033210028

January 22,2004

February 20, 2004

February 26, 2004

In a letter (signed by'T.' Mitchell), Entergy provided clarifications related to

questions from the staff's aging management audit. ML040300229

In' a letter (signed by'G.'S6ber), NRC provided Entergy a revised

schedule for the conduct of review for ANO-2. ML040550582

In a memorandum (signed by G. Suber), NRC summarized the

-December 15 and 16,'2004 conference calls between the NRC staff and

Entergy regarding draft Request for Additional Information (RAI)

-conceming the staff'sreview'of the LRA. ML040610542

March 8, 2004 In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional informatiorinconcerning its review of the LRA. ML040710466

March 24, 2004 In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information'concerning its review of the LRA. ML040710466

March 29, 2004 In a letter (signed by T. Mitchell), Entergy provided clarifications related to

questions from the staff's aging management audit. ML040860665

'' ' ' ' h- ?'staff' ''':-it..

April 6, 2004 In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls Felated t6 the staff's review of the LRA. ML041000168

April 13, 2004 In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information''coricerning its review of the LRA. ML041050820

April 14, 2004 In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041050858

B-1
April 19, 2004

April 23, 2004

May 5, 2004

May 11,2004

May 17, 2004

May 19, 2004

May 19,2004

May 19, 2004

May 19, 2004

May 24, 2004

May 25, 2004

May 26, 2004

June 10, 2004

June 11, 2004

June 16, 2004

June 21, 2004

In a letter (signed by L. Smith), NRC provided Entergy the Screening and

Scoping Inspection Report 05000368/2004-06. ML041100648

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041200384

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041280554

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041330486

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041380284

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041420057

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041420062

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041420067

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041420060

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041480292

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041470021

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041480134

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041670312

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041620247

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041700183

In a memorandum (signed by G. Suber), NRC summarized the May 20,

2004 conference call between the NRC staff and Entergy regarding draft

Request for Additional Information (RAI) concerning the staff's review of

the LRA. ML041730571
June 21, 2004

June 21, 2004

June 21, 2004

June 23, 2004

June 24, 2004

July 01, 2004

July 22, 2004

July 22, 2004

July 22, 2004

August 18, 2004

Sept. 10, 2004

Sept. 23, 2004

October 13, 2004

December 13, 2004

In a memorandum (signed by G. Suber), NRC summarized the March 24

and April 16, 2004 conference calls between the NRC staff and Entergy

regarding draft Request for Additional Information (RAI) concerning the

staff's review of the LRA. ML041730526

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041750125

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041750119

In a memorandum (signed by G. Suber), NRC summarized the March 24

and May 27, 2004 conference calls between the NRC staff and Entergy

regarding draft Request for Additional Information (RAI) concerning the

staff's review of the LRA. ML041770037

In a letter (signed by G. Suber), NRC provided ANO-2 requests for

additional information concerning its review of the LRA. ML041770557

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML041880147

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML042160356

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML042160349

In a letter (signed by T. Mitchell), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML042160860

In a letter (signed by D James), Entergy provided clarification responses

to NRC concerning RAls related to the staff's review of the LRA.

ML042660110

In a letter (signed by D. James), Entergy provided clarification responses

to NRC concerning RAls related to the staff's review of the LRA.

ML042390431

In a letter (signed by D. James), Entergy provided responses to NRC

concerning RAls related to the staff's review of the LRA. ML042790302

In a letter (signed by D. James), Entergy provided an annual update to

the LRA. ML043010592

In a letter (signed by D. James), Entergy provided comments on the Draft

Safety Evaluation Report. ML043560138

B-3
February 28, 2004 In a letter (signed by D. James), Entergy provided clarification on

responses to RAls related to the NRC staff's review of the LRA.

ML050670491

B-4
APPENDIX C: PRINCIPAL CONTRIBUTORS

.' -.;,1 1 . .

LICENSE RENEWAL AND

Name

Pao-Tsin Kuo

Samson Lee

Gregory Suber

Thelma Davis

Yvonne Edmonds

Melissa Jenkins

Kimberley Corp

Juan Ayala

Tae Kim

Kamishan Martin

Maurice Heath

Frank Akstulewicz

Hansraj Ashar

Jose Calvo

Terence Chan

Stephanie Coffin

Gregory Cranston

Robert Dennig

Richard Dipert

James Drake

Johnny Eads

Greg Galletti

George Georgiev

Raj Goel

Jin-Sien Guo

Mark Hartzman

Gene Imbro

Ronaldo Jenkins

John Knox

Carolyn Lauron

Arnold Lee

Andrea Lee

Chang Li

Renee (Yueh-Li) Li

Tilda Liu

Louise Lund

John Ma

Kamal Manoly

James Medoff

Richard McNally

ENVIRONMENTAL IMPACTS PROGRAM

RESPONSIBILITY

--Branch Chief

<-Section Chief

Project Manager

Clerical Support

'Administrative Support

Administrative Support

Technical Support

Technical Support

Technical Support

Technical Support

Technical Support

Management Supervision

Civil Engineering

Management Supervision

:Management Supervision

Management Supervision

Team Leader

Management Supervision

Fire Protection

Regional Inspector

Project Manager

Quality Assurance

Materials Engineering

Safety Assessment

Plant Systems

Civil Engineering

Management Supervision

Electrical Engineering

Electrical Engineering

Materials Engineering

Mechanical Engineering

Materials Engineering

Plant Systems

Mechanical Engineering

Project Management

Management Supervision

Civil Engineering

Management Supervision

Materials Engineering

Mechanical Engineering

C-1
Matthew McConnell

Rebecca Nease

Duc Nguyen

Janak Raval

Bill Roger

David Solorio

David Terao

Dale Thatcher

George Thomas

John Tsao

Harold Walker

Steve West

Sunil Weerakkody

Electrical Engineering

Inspection Team Leader

Electrical Engineer

Safety Assessment

Quality Assurance

Management Supervision

Management Supervision

Management Supervision

Reactor Systems

Materials Engineering

Safety Assessment

Management Supervision

Management Supervision

CONTRACTORS

Contractor

Kim Green

Richard Morante

Shuiwing Pam

Steve Pope

Technical Area

Mechanical Engineering

Civil Engineering

Mechanical Engineering

Team Leader

C-2
APPENDIX D: REFERENCES

This appendix contains a listing of references used in the preparation of the Safety Evaluation

Report prepared during the review of the license renewal application for Arkansas Nuclear One,

Unit 2, Docket Number 50-368.

American Society of Mechanical Engineers (ASME)

ASME Code, Section III

ASME Code, Section ill, Class 1

ASME Code, Section III, Classes 2 and 3

ASME Code, Section 1II, Subsection NC-3200

ASME Code, Section Vill, Division 1

ASME Code, Section Vil, Division 2

ASME Code, Section Vil, Division 1; AWWA; or MSS

ASME Code, Sections Vil or l1l, Subsections NC or ND

ASME Code, Section XI

ASME Code, Section Xl, Subsection IWL

ASME Code Appendix G to Section XI

ASME Code Case N-481

ASME Code Case N-588

ASME Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T

Limit Curves, Section Xl, Division 1,"

ANSI B31.1, Power Piping -

American Society for Testing and Materials (ASTM)

ASTM E185-82, "Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels"

ASTM E-1 85, "Standard Practice for Conducting Surveillance Tests for Light Water Cooled

Nuclear Power Vessels"

ASTM standard D 1796, Staridard -Test Methi6d for Water and Sedimient in Fuel Oils by the

Centrifuge Method (Laboratory Procedure), 2002

D-1
ASTM standard D 2709, Standard Test Method for Water and Sediment in Middle Distillate

Fuels by Centrifuge, 2001

ASTM standard D 2276, Standard Test Method for Particulate Contaminant in Aviation Fuel by

Line Sampling

ASTM Standard D 4057, Standard Practice for Manual Sampling of Petroleum and Petroleum

Products, 2000

Code of Federal Regulations (CFR)

10 CFR 50.34a, Design Objectives for Equipment to Control Release of Radioactive Material In

Effluents - Nuclear Power Reactors, US Nuclear Regulatory Commission

10 CFR 50.48, Fire Protection, US Nuclear Regulatory Commission

10 CFR 50.49, Environmental Qualification of Electric Equipment to Safety For Nuclear Power

Plants, US Nuclear Regulatory Commission

10 CFR 50.55a, Codes and Standards, US Nuclear Regulatory Commission

10 CFR 50.59, Changes, Tests, and Experiments, US Nuclear Regulatory Commission

10 CFR 50.61, Fracture Toughness Requirement For Protection Against Pressurized Thermal

Shock Events, US Nuclear Regulatory Commission

10 CFR 50.62, Requirements For Reduction of Risk From Anticipated Transients Without

Scram (ATWS) Events For Light-Water-Cooled Nuclear Power Plants, US Nuclear Regulatory

Commission

10 CFR 50.63, Loss of All Alternating Current Power, US Nuclear Regulatory Commission

10 CFR 50.67, Accident Source Term, US Nuclear Regulatory Commission

10 CFR 50 Appendix J, Primary Reactor Containment Leakage Testing For Water-Cooled

Power Plants, US Nuclear Regulatory Commission

10 CFR 54.21, Contents of Application-Technical Information, US Nuclear Regulatory

Commission

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

US Nuclear Regulatory Commission

10 CFR 54.4, Scope, US Nuclear Regulatory Commission

10 CFR 54.30, Matters Not Subject To A Renewal Review, US Nuclear Regulatory Commission

10 CFR 100.11, Determination of Exclusion Area, Low Population Zone, and Population Center

Distance, US Nuclear Regulatory Commission

D-2
29 CFR Chapter XVII, 1910.134, Respiratory Protection, US Nuclear Regulatory Commission

29 CFR Chapter XVII, 1926.134, Respiratory Protection, US Nuclear Regulatory Commission

42 CFR Chapter I, Part 84, Approval of Respiratory Protective Devices, US Nuclear Regulatory

Commission

Entergy Operations, Inc.

Entergy Letter No. OCAN070404, Response to NRC 2004-01 Regarding Inspection of Alloy

82/182/600 Materials Used in Pressurizer Penetrations and Steam Space Piping Components

(July 27, 2004)

Entergy Letter No. Letter No. 2CAN090402, dated September 10, 2004.

Entergy Letter No. 2CAN090403, dated September 23, 2004

Engineering Report 02-R-2008-01, the Scoping Methods and Results Report

Engineering Report A2-EP-2002-004, UTLAA and Exemption Evaluation"

Engineering Report A2-ME-2003-001 -0, Revision 1, Section 3.62, "Plant Heating," and Section

3.87, "Turbine Building Sump," -

Engineering Report A2-ME-2003-001 -1, "Aging Management Review of Nonsafety-related

Systems and Components Affecting Safety-related Systems"

Electric Power Research Institute (EPRI) and Material Reliability Program (MRP)

EPRI NP-1406-SR, "Nondestructive Examination Acceptance Standards."

EPRI NP-5067, Good Bolting Practices

EPRI NP-5569, Chromate Substitutes for Corrosion Inhibitors in Cooling Systems, December

1987

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power. Plants, Volumes 1 and 2,

May 1988

EPRI TR-1 05714, PWR Primary Water Chemistry Guidelines: Vol. 1: Revision 4; Vol. 2:

Revision 4 Volume 2, January 1999

EPRI TR-102134,Revision 5, PWR Secondary Water Chemistry Guidelines, January 1999

EPRI TR-104213, Bolted Joint Maintenance & Applications Guide, December 1995

EPRI TR-1 05504, Primer on Maintaining the Integrity of Water-Cooled Generator Stator

Windings, October 1995

D-3
EPRI TR-1 07396, Closed Cooling Water Chemistry Guidelines, April 2004

Nuclear Energy Institute (NEI)

NEI 95-10, Industry Guidelines for Implementing the Requirement of 1 OCFR Part 54 The

License Renewal Rule, Revision 3, March 2001

NEI 97-06, Steam Generator Program Guidelines

United States Nuclear Regulatory Commission (NRC}

Bulletins

(IE) Bulletin 79-01 B, "Environmental Qualification of Class IE Equipment ," February 8, 1979

NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems," June

22,1988

NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification," December 20, 1988

NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration

Nozzles," August 3, 2001

NRC Bulletin 2002-01, uReactor Pressure Vessel Head Degradation and Reactor Coolant

Pressure Boundary Integrity," March 18, 2002

NRC Bulletin 2002-02, "Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle

Inspection Programs," August 9, 2002

NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600 Materials Used in the Fabrication of

Pressurizer Penetrations and Steam Space Piping Connections at Pressurized-Water

Reactors," May 28, 2004

Executive Orders

NRC Order EA-03-009, ISSUANCE OF ORDER ESTABLISHING INTERIM INSPECTION

REQUIREMENTS FOR REACTOR PRESSURE VESSEL HEADS AT

PRESSURIZED WATER REACTORS

Generic Safety Issue

GSI-1 66, Adequacy of the Fatigue Life of Metal Components

GSI-168, EQ of Electrical Components

GSI-1 90, Fatigue Evaluation of Metal Components for 60-year Plant Life

Information Notices

NRC Information Notice (IN) 89-33, "Potential Failure of Westinghouse Steam Generator Tube

Mechanical Plugs,"

NRC Information Notice (IN) 89-65, "Potential For Stress Corrosion Cracking in Steam

Generator Tube Plugs Supplied by Babcock and Wilcox," September 8, 1989

D-4
NRC Information Notice (IN) 90-04, "Cracking of The Upper Shell-to-transition Cone Girth

Welds in Steam Generators," January 26, 1990

NRC Information Notice (IN) 92-20, "Inadequate Local Leak Rate Testing"

NRC Information Notice (IN) 94-87, "Unanticipated Crack in a Particular Heat Of Alloy 600 Used

For Westinghouse Mechanical Plugs For Steam Generator Tubes," December 1994

NRC Information Notice (IN) 99-10, 'Degradation of Prestressing Tendon Systems in

Prestressed Concrete Containment," October 1999

Generic Letters

NRC Generic Letter (GL) 88-05, "Boric Acid Corrosion Of Carbon Steel Reactor Pressure

Boundary Component in PWR Plants,' March 17,1988

NRC Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-Related.

Equipment," July 18, 1989

Inspection Reports

NRC 2004-01 Regarding Inspection of Alloy 82/182/600 Materials Used in Pressurizer

Penetrations and Steam Space Piping Components (July 27, 2004)

NRC Inspections Guideline 71111.08, unservice Inspection Activities."

Miscellaneous

Interim Staff Guidance (ISG)-2, "NRC Staff Position on License Renewal Rule (10 CFR 54.4)

As It Relates to the Station Blackout Rule (SBO) (10 CFR 50.63)

SECY-95-245, uCompletion of the Fatigue Action Plan," September 25, 1995

Regulatory Information Summary (RIS) 2003-09

ISO 4406, "Hydraulic fluid power - Fluids -- Method for coding the level of contamination by

solid particles," 1999 -

NUREG-Series Reports

NUREG-0313, Technical Report on Material Selection and Processing Guidelines for BWR

Coolant Pressure Boundary Piping," U.S. Nuclear Regulatory Commission, July 1977, (Rev. 1)

July 1980, (Rev. 2) January 1988 -

NUREG-1743, "Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear

One, Unit 1."

NUREG-1766, Section 2.1.3.1, "Safety Evaluation Report Related to the License Renewal of

North Anna Power Station, Units 1 and 2, and Surry Power Station, Units 1 and 2," December

2002

NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," April 2001 i

D-5
NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory

Commission," April 2001

NUREG/CR-6177, "Assessment of Thermal Embrittlement of Cast Stainless Steels,"

"PWR Materials Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plants

(MRP-44), Part 1: Alloy 82/182 Pipe Butt Welds,"

NUREG/CR 6717, Section 5.3, "Environmental Effects on Fatigue Crack Initiation in Piping and

Pressure Vessel Steels," May 2001.

Regulatory Guides

NRC Regulatory Guide 1.14, Revision 1, Reactor Coolant Pump Flywheel Integrity (August

1975)

NRC Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear

Power Plants

NRC Regulatory Guide 1.190, "Calculational and Dosimetry Methods for Determining Pressure

Vessel Neutron Fluence (March 2001)"

NRC Regulatory Guide 1.46, "Protection Against Pipe Whip Inside Containment,"

NRC Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement' of Reactor Vessel Materials

(May 1988),"

Industry Reports

Babcock & Wilcox

Babcock & Wilcox report BAW-2241 P-A, Revision 1, "Fluence and Uncertainty Methodologies,"

Babcock and Wilcox report BAW-2241 P-A, Revision 1, "Fluence and Uncertainty

Methodologies," which was published in April 1999.

Babcock and Wilcox Topical Report BAW-2399, Analysis of Capsule W-1 04, Entergy

Operations, Inc., Arkansas Nuclear One Unit 2 Power Plant (September 2001).

Combustion Engineering

CEN-367-A, Revision 000, Leak-Before-Break Evaluation of Primary Coolant Loop Piping in

Combustion Engineering Designed Nuclear Steam Supply Systems

CE-NPSD-448, Review of Inhibitors used in Closed Cycle Cooling Water Systems

CE NPSD-1 198-P, Revision 00, Low-Alloy Steel Component

Corrosion Analysis Supporting Small-Diameter Alloy 600/690 Nozzle Repair/Replacement

Programs

Combustion Engineering Topical Report No. A-NLM-005, dated October 30, 1974

Combustion Engineering Topical Report No. TR-MCD-002, dated March 1976

D-6
Westinghouse Topical Reports (WCAP)

WCAP-1 5973-P, "Low-Alloy Steel Component Corrosion Analysis Supporting Small-Diameter

Alloy 600/690 Nozzle Repair/Replacement Programs,"

D-7
APPENDIX E: REQUEST FOR ADDITIONAL INFORMATION

Request for Additional Information (RAI) I Issuance Date Response Date

Section 1

Section 2: Structures and Components Subject to Aging Management Review

Section 2.1 Scoping and Screening Methodology

RAI 2.1-1 February 26, 2004 May 19, 2004

RAI 2.1-2

RAI 2.1-3 April 13, 2004 May 19, 2004

RAI 2.1 -4

RAI 2.1-5

RAI 2.1-6

RAI 2.1-7

Section 2.2 Plant Level Scoping '

RAI 2.2-1 May 11,2004 | June -10, 2004

if

.. . . . I.

..... .I.. I

E-1
Section 2.3 Systems Scoping and Screening: Mechanical

RAI 2.3-1

RAI 2.3.3.3-1

RAI 2.3.3.4-1

RAI 2.3.3.11-1

RAI 2.3.3.12-1

RAI 2.3.3.12-2

RAI 2.3.3.12-3

RAI 2.3.4.1-1

RAI 2.3.4.2-1

RAI 2.3.4.3-1

RAI 2.3.4.3-2

May 11,2004 June 10, 2004

RAI 2.3-1a April 8,2004 May 19, 2004

RAI 2.3-1 b

RAI 2.3-1c

RAI 2.3-2

RAI 2.3-3a

RAI 2.3-3b

RAI 2.3-4

RAI 2.3-5

RAI 2.3.1.1-1 April 23,2004 May 24,2004

RAI 2.3.1.4-1

RAI 2.3.1-2-1

RAI 2.3.1-2-2

RAI 2.3.1-2-3

RAI 2.3.1-2-6

RAI 2.3.1-2-7

RAI 2.3.1-2-8

RAI 2.3.1-3-1

RAI 2.3.1-5-1

RAI 2.3.1-5-2

RAI 2.3.1-5-3

RAI P&ID-1

Section 2.4 Scoping and Screening Results: Structures

RAI 2.4-la April 14,2004 May 19, 2004

RAI 2.4-lb

RAI 2.4-1c

RAI 2.4-2

RAI 2.4-3

RAI 2.4-4

RAI 2.4-5

RAI 2.4-6

RAI 2.4-7

RAI 2.4-8

E-2
Section 2.5 Scoping and Screening Results- Electrical and Instrumentation Controls

RAI 2.5-1 - ; - May 25, 2004 - June 21, 2004

- RAI 2.5-2 - May 25, 2004 - . August -18, 2004

RAI 2.5-3 May 25, 2004 June 21, 2004 --

. . . ... ..

'''

.I

i

!-

j -.

'i

...i

E-3
Section 3: Aging Management Review Results

Section 3.1 Aging Management of Reactor Vessels, Internals, and Reactor Coolant

System

RAI 3.1.1-1 May 26, 2004 July 1,2004

RAI 3.1.1-2

RAI 3.1.1-3

RAI 3.1.1-4

RAI 3.1.2-1.1 June 11, 2004 July 22, 2004

RAI 3.1.2-1.2

RAI 3.1.2-1.3

RAI 3.1.2-1.4

RAI 3.1.2-2.1

RAI 3.1.2-3.1

RAI 3.1.2-4.1

RAI 3.1.2-4.2

RAI 3.1.2-4.5

RAI 3.1.2-5.1 May 26, 2004 July 1,2004

RAI 3.1.2-5.2

RAI 3.1.2-5.3

RAI 3.1.2-5.4

RAI 3.1.2-5.5

RAI 3.1.2-5.6 May 26, 2004 July 1, 2004

RAI 3.1.2-5.7

RAI 3.1.2-5.8

RAI 3.1.2-5.9

RAI 3.1.2-5.10

RAI 3.1.2-5.11

RAI 3.1.2-5.12

RAI 3.1 .2-5.13

RAI 3.1.2-5.14 _ _ _ _ _ _ _ _ _

E-4
Section 3.2 Aging Management of Engineered Safety Features

RAI 3.2-1

RAI 3.2-2

RAI 3.2-3

RAI 3.2-4

RAI 3.2-5

RAI 3.2-6

RAI 3.2-7

RAI 3.2-8

RAI 3.2-9

I March 8, 2004 April 6, 2004

RAI 3.2-10

RAI 3.2-11 June 24, 2004 July 22, 2004

RAI 3.2-12

Section 3.3 Aging Management of Auxiliary Systems

RAI 3.3-1 May 5, 2004 June 21,2004

RAI 3.3-2

RAI 3.3-3

RAI 3.3-4

RAI 3.3.2.4.1-1

RAI 3.3.2.4.3-1

RAI 3.3.2.4.3-2

RAI 3.3.2.4.4-1

RAI 3.3.2.4.5-1

RAI 3.3.2.4.7-1

RAI 3.3.2.4.8-1

RAI 3.3.2.4.8-2

RAI 3.3.2.4.10-1

RAI 3.3.2.4.11-1 June 21,2004

September 23,

2004

E-5
I RAI 3.3-6 | May 26, 2004 l

E-6
Section 3.4 Aging Management of Steam and Power Conversion Systems

RAI 3.4-1

RAI 3.4-2

RAI 3.4-3

RAI 3.4-4

RAI 3.4-5

RAI 3.4-6

RAI 3.4-7

March 8, 2004 April 6, 2004

.. '' -.11

Section 3.5 Aging Management of Containments, Structures, and Components,

RAI 3.5-1

RAI 3.5-2

RAI 3.5-3

RAI 3.5-4

RAI 3.5-5

RAI 3.5-6

RAI 3.5-7

RAI 3.5-8

RAI 3.5-9

.

April 14, 2004 May 19, 2004

July 22,-2004

Section 3.5 Electrical Instrumentation and Controls

No RAI Issued I na na

Section 4 Time-Limited Aging Analyses

Section 4.2 Reactor Vessel Neutron Embrittlement

RAI 4.2-1 June 11, 2004 July 22, 2004

RAI 4.2-2

Section 4.3 Metal Fatigue

RAI 4.3.1-1 May 17, 2004 June 16, 2004

RAI 4.3.1-2

RAI 4.3.1-3

RAI 4.3.1-4

E-7
RAI 4.3.2-1

RAI 4.3.2-2

RAI 4.3.2-3

RAI 4.3.3.3-1

Section 4.4 Environmental Qualification of Electrical Equipment

No RAI Issued

Section 4.5 Concrete Containment Tendon Prestress

RAI 4.5-1 May 17, 2004 July 22, 2004

RAI 4.5-2 July 22, 2004

September 10,

2004

RAI 4.5-3 July 22, 2004

E-8
Section 4.6 Containment Liner Plate and Penetration Fatigue Analyses

RAI 4.6-1 May 17, 2004 June 16, 2004

RAI 4.6-2

Section 4.7 Other Plant-Specific Time-Limited Aging Analyses

Section 4.7.1 Reactor Coolant System Piping Leak-Before-Break Analysis

RAI 4.7.1-1 June 1, 2004 July 22, 2004

Section 4.7.2 Reactor Coolant Pump Code Case N-481

RAI 4.7.2-1 J June 1,2004 July 22, 2004

RAI 4.7.2-2 1

Section 4.7.3 Reactor Coolant Pump Flywheel

RAI 4.7.3-1 1 June 1,2004 September 10,

1 |2004

Section 4.7.4 Steam Generator Tubes - Flow-induced Vibration

No RAI Issued I na na

Section 4.7.5 Alloy 600 Nozzle Repairs

RAI 4.7.5-1 June 1,2004 July 22, 2004

RAI 4.7.5-2

Section 4.7.6 High Energy Line Break Analysis

RAI 4.7.6-1 | May 17,2004 |June 16, 2004

E-9
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 hIstructions on the retem) NUREG-1828

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report related to the License Renewal of the Arkansas Nuclear One, Unit 2MONTH | YEAR

June 2005

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Gregory F. Suber

7. PERIOD COVERED (indushm Dates)

8. PERFORMING ORGANIZATION -NAME AND ADDRESS (INNRC prvide Dhvisin. Ote rRegin, U.S NudearReguetoryCommsin andmaingeoddress f contdtor,

proade narne and maling address )

Division of Regulatory Improvement Programs (DRIP)

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (fftNRC "Spne Owa bovntreotrvcopr ede NRC Dilon, OftveOrRegn, V.S. Nud~earRegulatoy Coranmon,

and maig address)

Same as above

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 Words or ess)

The safety evaluation report (SER) documents the technical review of the Arkansas Nuclear One, Unit 2 (ANO-2), license

renewal application (LRA) by the U.S. Nuclear Regulatory Commission staff (staff). By letter dated October 14, 2003, Entergy

Operations, Inc. (Entergy or the applicant), submitted the LRA for ANO-2 in accordance with Title 10 of the Code of Federal

Regulations Part 54. Entergy Is requesting renewal of the operating license for ANO-2, (Facility Operating License No. NPF-6)

fora period of 20 years beyond the current expiration date (midnight, July 17, 2018).

The ANO site is located in southwestern Pope County, Arkansas, on a peninsula formed by Lake Dardanelle. The NRC Issued

ANO-2 construction permit on December 6, 1972. The operating license was issued by the NRC on

September 1, 1978. ANO-2 consists of a Combustion Engineering pressurized water reactor to generate

3026 megawatts-thermal (MWt) or approximately 1023 megawatts-electric (MWe).

This SER presents the staffs review of Information submitted to the NRC In the application. The staffs conclusion of is review

of the ANO-2 LRA can be found In Section 6 of this SER.

The NRC ANO-2 license renewal project manager is Mr. Gregory F. Suber. Mr. Suber may be reached at 301-415-1124.

Written correspondence should be addressed to the Licensee Renewal and Environmental Impacts Program,

U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.

12. KEY WORDS/DESCRIPTORS (List words orphrases that wX ass researhers I axt t repod) 13. AVAILABILTY STATEMENT

license renewal, nuclear power unlimited

14 SECURITY CLASSIFICATION

unclassified

(This Rept

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-2004) PRIMTLO ON RECYCLED PAPER
LPrinted

on 

IN

recycled

paper

Federal Recycling Program i
I . .Ia

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS

I